Text

Proposed License Amendment Request Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirement to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)
	ML100900391
Person / Time
Site:	Surry
Issue date:	03/30/2010
From:	Price A; Virginia Electric & Power Co (VEPCO)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	10-183, TSTF-425, Rev 3
	Download: ML100900391 (102)
	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.10-183 NL&OS/ETS RO Docket Nos. 50-280/281 License Nos. DPR-32/37 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY 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 DPR-32 and DPR-37, for Surry Power Station Units 1 and 2, respectively. The proposed amendments will modify Surry TSby relocating specific surveillance frequencies to a licensee-controlled program with the implementation of Nuclear Energy Institute (NEI) 04-10, "Risk-lnformed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies."

The changes are consistent with NRC-approved Industry Technical Specifications Task Force (TSTF) Standard Technical Specifications (STS) change TSTF-425, 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 variations and verifications. Attachment 2 provides documentation of the Probabilistic Risk Assessment (PRA) technical adequacy. Attachment 3 provides the marked-up Surry Units 1 and 2 TS pages to show the proposed changes. Attachment 3 also provides the proposed TS Bases changes for information. provides a TSTF-425 (NUREG-1431) versus Surry TS Cross-Reference. Attachment 5

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 amendment being implemented within 120 days.

Serial NO.1 0-183 Docket Nos. 50-280/281 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, r

J. AI Ice Vice Pr sident - Nuclear Engineering Attachments:

1. Description and Assessment

2. Documentation of PRA Technical Adequacy

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

4. TSTF-425 (NUREG-1431) vs. Surry TS Cross-Reference

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

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COUNTY OF HENRICO

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The foregoing document was acknowledged before me, rh 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 50~ay of ~L6

' 2010.

My Commission Expires: ~ 3//,201a. ~.tJ/;.A.Lf..--

Notary Public VICKI L. HULL Notary Public

~

Commonwealth of Virginia

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140542 My CommIssion ExpIres May 31, 2010 ~

cc:

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, Georgia 30303 NRC Senior Resident Inspector Surry 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.10-183 Docket Nos. 50-280/281 LAR - Relocate Surveillance Frequencies from TS Page 3 of 3

Serial No.1 0-183 Docket Nos. 50-280/281 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 1 DESCRIPTION AND ASSESSMENT VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

Serial No.10-183 Docket Nos. 50-280/50-281 Page 1 of 5 DESCRIPTION AND ASSESSMENT OF PROPOSED CHANGES

1.0 DESCRIPTION

The proposed amendment would modify 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 6, Administrative Controls. The changes are consistent with NRC-approved Industry/TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6,2009 (74 FR 31996), 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 Surry Power Station Units 1 and 2 and justify this amendment to incorporate the changes to the Surry 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 (typed) 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 Surry amendment requests that may 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 0-183 Docket Nos. 50-280/50-281 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.

Also since the Bases for the SPS Surveillance Requirements are intermingled throughout the TS Surveillance Requirements sections, markups of both the TS changes and the proposed Bases changes are provided together in Attachment 3.

The proposed TS Bases changes are provided to the NRC for information.

2. The definition of STAGGERED TEST BASIS is being retained in Surry TS Definition Section 1 since this terminology is mentioned in Administrative TS Section 6.4.R, "Main Control Room/Emergency Switchgear Room (MCR/ESGR)

Envelope Habitability Program," 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 Surry basis for frequencies which do not, in all cases, base Frequency on operating experience, equipment reliability, and plant risk. In addition, other editorial changes to the existing TS wording and/or text inserts are being made.

These administrative/editorial deviations of the TSTF-425 inserts and the existing TS wording are necessary to fit the custom Technical Specification format.

4. Attachment 4 provides a cross-reference between the NUREG-1431 Surveillances included in TSTF-425 versus the Surry Surveillances included lrr this amendment request. Attachment 4 includes a summary description of the referenced TSTF-425 (NUREG-1431)/Surry 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 Surry Surveillances with plant-specific Surveillance numbers,

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

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

Serial No.10-183 Docket Nos. 50-280/50-281 Page 3 of 5 Concerning the above, Surry TS are custom Technical Specifications for a pressurized water reactor.

As a result, the applicable Surry TS and associated Bases number differ from the Standard Technical Specifications (STS) presented in NUREG-1431 and TSTF-425, but with no impact on the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 32996).

For NUREG-1431 Surveillances that are not contained in the Surry TS, the corresponding NUREG-1431 mark-ups included in TSTF-425 for these Surveillances are not applicable to Surry. 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 Surry 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 Surry 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. 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 structures, systems, and components, (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.

5. Editorial changes are being made to correct previous administrative/typographical errors.

The proposed words for TS 4.16 B were included as part of Amendment 2 issued by the NRC, dated October 17, 1974, but inadvertently omitted when the

Serial No.10-183 Docket Nos. 50-280/50-281 Page 4 of 5 amendment was incorporated into the Surry Technical Specification.

The following words are being added to restore the Technical Specification to the approved wording:

"B. Surveillance Requirements

1. Test for leakage and/or contamination shall be performed by the licensee or by other persons specifically authorized by the" Correct a Table number in TS 4.1.A. The current TS refers to Tables 4.1-1, 4.1-A and 4.1-2. However Table 4.1-A should be Table 4.1-1A.

6. In the Surveillance requirements for the Station Batteries and the Emergency Diesel Generator Batteries (TS 4.6.C and D) the requirement to "record" the readings/results of the surveillance is being deleted as unnecessary. The results of all surveillances performed are required to be recorded and maintained by the quality assurance program.

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 Surry Units 1 and 2, and is provided as Attachment 5 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 Surry 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.

Serial No.10-183 Docket Nos. 50-280/50-281 Page 5 of 5

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 Surry Units 1 and 2, and the determination is hereby incorporated by reference for this application.

5.0 REFERENCES

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

RITSTF Initiative 5b,"

March 18, 2009 (ADAMS Accession Number:

ML090850642).

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

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

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

January 2007 (ADAMS Accession Number: ML070240001).

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

Technical Specifications,"

dated August 1998 (ADAMS Accession No. ML003740176).

Serial No.10-183 Docket Nos. 50-280/281 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 2 DOCUMENTATION OF PRA TECHNICAL ADEQUACY VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

Serial No.10-183 Docket Nos. 50-280/50-281 Page 1 of 15 Documentation of PRA Technical Adequacy PRA Quality Overview The implementation of the Surveillance Frequency Control Program (also referred to as Technical Specifications Initiative 5b) at Surry Power Station (SPS) 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 change.

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

Serial No.10-183 Docket Nos. 50-280/50-281 Page 2 of 15 impact of all risk-informed STI revisions on all PRA evaluations (i.e., internal events, external events and shutdown) is also compared to the risk acceptance criteria as delineated in NEI 04-10, 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.

Serial No.1 0-183 Docket Nos. 50-280/50-281 Page 3 of 15 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.

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 S007Aa 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 SPS PRA is based on the event tree I 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 its operating 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 SPS PRA.

PRA Maintenance and Update The Surry Power Station (SPS) 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

Serial No.10-183 Docket Nos. 50-280/50-281 Page 4 of 15 Provide PRA model configuration control Create and maintain configuration risk evaluation tools for the Dominion Nuclear Fleet 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. Such departure must be evaluated and documented in accordance with applicable regulations and Dominion policies.

A procedurally controlled process is used to maintain configuration control of the SPS 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 (DE's) are appropriately screened, dispositioned, and scheduled for incorporation into the model. These processes help assure that the SPS 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.

The SPS 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.

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 Level 1 and Level 2 SPS PRA analyses were originally developed and submitted to the NRC in 1991 as the Individual Plant Examination (lPE) Submittal.

The SPS PRA has been updated many times, since the original IPE.

A summary of the SPS PRA history is as follows:

Original IPE (August 1991)

Individual Plant Examination External Events (IPEEE) 1991 through 1994

Serial No.10-183 Docket Nos. 50-280/50-281 Page 5 of 15 1998 -

Data update; update to address issues needed to support the Maintenance Rule program.

2001 - Data update; update to address more Maintenance Rule issues, address peer review Facts and Observations (F&Os).

2002 - Update RCP seal LOCA model due to installation of high temperature o-rings; added internal flooding, additional changes for Maintenance Rule and Safety Monitor.

2004 - Update to address applicable F&Os from North Anna peer review.

2005 - Update to include plant changes to reduce turbine building flood risk.

2006 - Data update and update to address MSPI requirements.

2006 - Update to support ESGR chilled water Tech Spec change; added loss of main control room HVAC and loss of instrument air to the model; added logic from the IPEEE fire and seismic models.

2009 - Data update; addressed ASME PRA Standard SRs that were not met; extensive changes throughout the model as the model was converted to CAFTA Fault Tree Analysis System. (CAFTA).

2009 - Updated Interfacing Systems LOCA (ISLOCA) initiator frequency, added EDG and MC diesel fails to load (FTL) basic events, and added rupture failure of the SW expansion joints for the CCW heat exchangers as flood scenarios (current model of record).

Comprehensive Critical Reviews The SPS PRA model has benefited from the following comprehensive technical PRA Peer Reviews:

NEI PRA Peer Review The SPS internal events PRA received a formal industry PRA Peer Review in 1998.

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 SPS review team used the "Westinghouse Owner's Group (WOG) Peer Review Process Guidance" as the basis for the review.

The general scope 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).

Serial No.10-183 Docket Nos. 50-280/50-281 Page 6 of 15 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. Categories A and B F&Os are considered significant enough that the technical adequacy of the model may be impacted. Categories C and D are considered minor. Subsequent to the peer review, the model has been updated to address a number of the F&Os. The model has been updated to address all Category A, Band D F&Os. There are only 3 Category C F&Os that need to be addressed:

F&O Description DE-1 Develop a system to initiating event dependency matrix to better show the dependencies modeled for each initiator. (PRACC record 4023)

DE-4 Develop master dependency matrices for front-line to front-line, for support to front-line, and initiator to system dependencies. (PRACC record 4023)

SY-13 Update references that support mission times that are less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

(PRACC record 4012)

All three of these involve documentation issues that do not impact the PRA model results and do not affect the technical adequacy of the PRA model. Records have been added in the PRACC database to track the tasks.

SPS PRA Self-Assessment A self-assessment of the SPS PRA against the ASME PRA Standard was performed by Dominion in 2007 using guidance provided in NRC Regulatory Guide RG 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results from Risk-Informed Activities".

This self-assessment was documented and used as a planning guide for the SPS 2007 model update.

Many of the Supporting Requirements (SRs) identified in the self-assessment as not meeting capability category II have been incorporated into the SPS S007Aa model. The model was completely redeveloped using CAFTA (it was previously a WINNUPRA model).

The following is a brief summary of the changes made during the model update:

1. The system fault trees were developed from the latest drawings and procedures.

2. The internal flooding analysis was upgraded as follows:

re-performed and fully documented walkdowns and data collection identified new flood scenarios and validated previous scenarios used the latest flood frequency methodology for calculating minor, major and spray type flood events upgraded flood analysis documentation to address the IF SRs

Serial No.10-183 Docket Nos. 50-280/50-281 Page 7 of 15

3. The data was updated with the latest plant-specific data.

4. New thermal hydraulic analyses were performed to support success criteria, human failure event timing and level II analyses.

5. Level II analysis was updated to meet the Large Early Release Supporting Requirements (LE SRs).

6. Room heatup calculations were performed for key areas.

The failure of HVAC systems were added to the model if supporting calculations indicated the need for them or if heatup calculations were unavailable.

7. The system model notebooks were completely reformatted to better document the information reviewed and used in the development of the new system models.

8. Updated the model as a result of a series of challenge review meetings by the Surry System Engineers of the PRA models and notebooks.

In the S007Aa 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 318 SRs, the SPS PRA does not meet 19 SRs (Le., gaps). Table 1 provides the status of identified gaps.

SPS PRA Focused Peer Review The Surry PRA model underwent a focused peer review in February 2010 using the PRA Peer Review Certification process performed by the Westinghouse Owners Group (WOG).

To determine whether a full scope or focused peer review was necessary, the changes to each of the model elements were reviewed to assess whether the changes involved either of the following:

new methodology significant change in the scope or capability If changes to an element involved either a new methodology or a significant scope or capability change, then the element requires a peer review as required in the ASME PRA standard (RA-Sb-2005).

Based on the assessment of the changes to each PRA model element, a peer review was performed on the following elements:

Serial No.10-183 Docket Nos. 50-280/50-281 Page 8 of 15 Element High Level Requirement IE - Initiating Events Review support system initiator modeling meets SRs IE-C6, cr. C8, C9, and C12.

AS - Accident Sequence Review upgraded event trees for SBO, RCP Seal LOCA, SGTR and ATWS meets all HLRs for AS.

HR - Human Reliability Review implementation of SPAR-H methodology meets Analysis HLR-HR-G.

IF - Internal Flooding Review internal flooding model meets all HLRs for IF.

QU - Quantification Review conversion to CAFTA meets HLRs for QU-B, C, and D.

The AS and IF elements required a full review against all of the High Level Requirements (HLRs). However, changes in the IE, HR and QU elements only required specific HLR verification. The review process included:

Review of PRA against the Technical Elements and associated Supporting Requirements (SRs) - Focus is on meeting Category II At the SR level, Review Team judgment used to assess whether the PRA meets one of the three Capability Categories for each of the SRs Evaluation of the PRA is supported by:

NEI 05-04 process Addenda to ASME/ANS PRA Standard RA-S-2008 SR interpretations from ASME website NRC clarifications and qualifications as provided in Appendix A of RG 1.200, Rev. 2 Reviewer experience and knowledge Consensus with fellow reviewers Input and clarifications from Host Utility As of March 2010, the final assessment has not been provided to Dominion. Once the final report has been issued by the Westinghouse Owners Group, the identified gaps will be incorporated into Table 1 and tracked until closure.

Serial NO.1 0-183 Docket Nos. 50-280/50-281 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 I ASME SR Gap For each flood IF-B1 No documentation on why None. This is judged to be a documentation

1 area, identify the floods in containment were consideration only and does not affect the potential sources of screened out.

technical adequacy of the PRA model.

floodino Gap The NRC IF-C3 No documentation Qualitative assessment of jet impingement,

2 clarification for Cat discussing how jet pipe whip, humidity, etc. will be addressed by II says to address impingement, pipe wipe, sensitivity per NEI 04-10, Revision 1 if jet impingement, humidity and other types of applicable to the specific STI evaluation.

humidity, etc.

failures impact plant qualitatively using systems.

conservative assumptions Gap Document the LE-G3 No documentation of LERF None. This is judged to be a documentation

3 relative contribution contributions for accident consideration only and does not affect the of contributors to sequences.

technical adequacy of the PRA model.

LERF Gap Uncertainties shall QU-E1 Sources of model None. This is judged to be a documentation

4 be characterized QU-E2 uncertainties and consideration only and does not affect the and documented.

QU-F4 assumptions were not technical adequacy of the PRA model.

SC-C3 identified and documented.

Gap Estimate LE-F3 No parametric uncertainty None. This is judged to be a documentation

5 uncertainty QU-E3 analysis was performed.

consideration only and does not affect the intervals associated QU-F2 technical adequacy of the PRA model.

with parameter uncertainties.

Serial NO.1 0-183 Docket Nos. 50-280/50-281 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 I Comment Importance to Application I ASME SR Gap Evaluate the QU-E4 No sensitivities of model None. This is judged to be a documentation

6 sensitivity of the uncertainties and consideration only and does not affect the results.

assumptions were technical adequacy of the PRA model.

performed.

Gap Document the SY-C2 All documentation None. This is judged to be a documentation

7 system functions requirements are considered consideration only and does not affect the and boundaries.

met except for completion of technical adequacy of the PRA model.

walkdown checklists.

Gap Document AS-C3 Document uncertainties and None. This is judged to be a documentation

8 uncertainties and DA-E3 assumptions associated consideration only and does not affect the assumptions

. HR-13 with:

technical adequacy of the PRA model.

IE-D3 accident sequence IF-F3 analysis SC-C3 data analysis SY-C3 human reliability analysis initiating event analysis internal flooding analysis success criteria development system analysis

Serial No.10-183 Docket Nos. 50-280/50-281 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 SPS 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 SPS "non-seismic external events and fires" IPEEE study are documented in the SPS IPEEE Main Report [Ref. 3].

An additional "seismic" IPEEE study was submitted in December 1994 [Ref. 4].

Each of the SPS 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 SPS IPEEE Submittal [Ref. 7].

In addition to internal fires and seismic events, the SPS IPEEE analysis of high winds or tornadoes, external floods, transportation accidents, nearby facility accidents, 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 ofExternal Events Evaluation Seismic PRA Generic Letter 88-20, Supplement 4 [Ref. 9] 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, Surry 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 December 1997.

For the seismic event, Surry Power Station was categorized in NUREG-1407 as a focused scope plant.

As identified in Surry's December 1991 letter, the Seismic Probabilistic Risk Assessment (SPRA) (EPRI) with enhancements was selected for Surry Power Station. A completion schedule for IPEEE - Seismic was initially provided

Serial No.10-183 Docket Nos. 50-280/50-281 Page 12 of 15 by Surry 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, Surry submitted a revised approach to NRC in November 1995.

This approach, while still retaining the SPRA methodology and treating Surry 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 Surry Power Station has been performed in accordance with the SPRA methodology for a focused plant and Surry's stated commitments.

In February 1996, a peer review was conducted to assess the implementation of the IPEEE - Seismic program at Surry. This review included walkdown of about 15% of the items representing all classes of equipment in the Safe Shutdown Equipment List.

Although a few open issues were noted at the time of the review, the reviewer concluded that the Seismic Review Teams involved did a seismic walkdown review at Surry.

In summary, the IPEEE-Seismic program, integrated with the USI A-46 effort, resulted in several plant improvements and design modifications.

The SPRA quantification concluded that no severe accident vulnerabilities exist at Surry Power Station from the seismic event.

No other cost beneficial upgrade can be performed to improve the seismic margin and the core damage frequency of the plant.

Fire PRA Reference 3 documents the IPEEE fire analysis for Surry. Based on experience gained during the performance of the IPE, the differences between Units 1 and 2 are of little significance.

Therefore, consistent with the NRC guidance, a limited analysis of the second unit was performed. This analysis involved a walkdown and resolution of any differences that were identified.

The IPEEE fire PRA follows the acceptable methods referred to in sections 4 and 5 of NUREG-1407. These methods include screening and bounding calculations in addition to detailed PRA analysis.

Portions of the EPRI Fire Induced Vulnerability Evaluation (FIVE) methodology have been adopted, particularly in the areas of location screening and fire frequency evaluation for the fire PRA. Procedures for performing, documenting and reviewing each individual task were developed in order to comply as closely as possible with the Quality Assurance requirements specified in 10 CFR 50 Appendix B.

Serial No.1 0-183 Docket Nos. 50-280/50-281 Page 13 of 15 The fire modeling process screened out all but four areas as insignificant contributors to core damage risk.

These are the emergency switchgear room, normal switchgear room, cable vault & tunnel, and control room.

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.

It was found that each of the issues have been adequately addressed at Surry.

Other External Hazards The other external hazards, as identified by NUREG/CR-2300 and NUREG/CR-4839, have been taken into consideration. Following the initial screening, seven events were identified as needing more detailed evaluation.

These events included aircraft accidents, external flooding, tornado generated missiles and high winds, pipeline accidents, transportation accidents, accidents in nearby industrial or military facilities, and release of chemicals from on-site storage.

Since the effects of these external events on Surry Power Station were analyzed as part of NUREG-1150, the analysis performed in the IPEEE used the method and in some cases the results obtained by NUREG/CR-4550.

However, in each case the Surry Updated UFSAR information was used to make sure that the results obtained by NUREG/CR-4450 were still valid.

The study concluded that there are no significant external events other than those identified in NUREG-1407.

The non-seismic external events of interest, except for aircraft impacts, pipeline accidents and external flooding, were screened out based on the UFSAR information and the results reached by the NUREG/CR-4550.

The bounding analysis performed for the effects of aircraft impacts and pipeline accidents were based on the methods used by NUREG/CR-4550.

The results of these two analyses indicate that the frequency of the events occurring is small.

The actual risk from these hazards to the safe operation of the plant would be less than the screening value, because most safety related equipment is inside Class I structures and is designed to withstand the loads imposed by the external event. The bounding analysis for external flooding considered the worst case occurrence of the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in 1 square mile probable maximum precipitation (PMP). The consequences of this occurrence were mitigated by implementation of a procedural revision and modification of turbine building roof parapets to reduce roof top accumulation during intense precipitation.

Therefore, it can be concluded that non-seismic external events do not pose a significant risk to the safe operation of Surry Power Station.

Serial NO.1 0-183 Docket Nos. 50-280/50-281 Page 14 of 15 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 SPS PRA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that the full power internal events SPS 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 reviewed to determine which, if any, would merit application-specific sensitivity studies in the presentation of the application results.

In addition, the SPS PRA has been used in support of various regulatory programs and relief requests that have received NRC SERs, further indication of the quality of the SPS PRA and suitability for regulatory applications. This list includes:

SPS IPE and IPEEE SERs SPS was a reference plant evaluated in NUREG/CR-1150; SPS IPE was compared to NUREG/CR-1150 model Risk-Informed Inservice inspection (RI-ISI)

Risk-informed EDG fuel tank technical specification change RG 1.200 pilot plant evaluation by NRC Life Extension (SAMA) License Amendment Maintenance Rule Program Mitigating Systems Performance Index (MSPI)

Significance Determination Process evaluations Risk Informed Technical Specification Changes o

Underground fuel oil storage tanks 7-day AOT o

Pressurizer PORV bottled air AOT o

RPS & ESFAS Surveillance Test Interval o

Containment Type "A" Surveillance Test Interval o

ESGR Chilled Water Replacement AOT

Serial No.10-183 Docket Nos. 50-280/50-281 Page 15 of 15 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 - Surry Power Station Units 1 And 2," Virginia Electric And Power Company, December 1994.

4.

"Surry 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," November 1997.

5.

Surry Power Station Probabilistic Safety Assessment Peer Review Certification Report, August, 1998.

6.

Surry Power Station Units 1 and 2 Probabilistic Risk Assessment Model Notebook Part IV, Appendix A.1, Revision 2,

"Internal Events Model Self-Assessment Update," June 2009.

7.

Letter from Mr. Gordon E. Edison (USNRC) to Mr. David A. Christian, Virginia Electric Power Company, Surry Power Station, Units 1 and 2 -

Review of Individual Plant Examination of External Events (IPEEE) (TAC NOS. M83681 and M3682), June 2000.

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), PRA Procedures Guide, NUREG/CR-2300, American Nuclear Society and Institute of Electrical and Electronic Engineers, January 1983.

11.

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

Serial No.10-183 Docket Nos. 50-280/281 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 3 MARKED-UP TECHNICAL SPECIFICATION AND BASES CHANGES VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

G.

Reactor Coolant System Overpressure Mitigation Specification TS 3.1-23 O~-Ol-~5 in accordance with the frequency specified in the Surveillance Frequency Control Program.

1.

The Reactor Coolant System (RCS) overpres re mitigating system shall be OPERABLE as described below:

a.

Whenever the RCS average temperatu e is greater than 350oP, a bubble shall exist in the pressurizer with the neces ary sprays and heaters OPERABLE.

b.

Prior to decreasing RCS average tern erature below 350oP, verify a maximum of one charging pump is capable of i [ecting into the RCS and that each accumulator is isolated. Thereafter, OHee per 12 am:trs:

(1)

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

(2)

Verify that each accumulator is isolated, if isolation is required.

c.

Whenever the RCS average temperature is less than or equal to 3500P and the reactor vessel head is bolted:

(1)

A maximum of one charging pump shall be OPERABLE and capable of injecting into the RCS. Two charging pumps may be in operation momentarily during transfer of operation from one charging pump to

/

another.

and (2)

The accumulators shall be isolated (accumulator discharge valves closed and their respective breakers locked, sealed or otherwise secured in the open position). Isolation is not required if the accumulator pressure is less than the pressurizer PORV setpoint specified in TS 3.1.G.1.c.(4).

and Amendment Nos. 204 aHd204

and the vent path verified open in accordance with the frequency specified in the Surveillance Frequency Control Program.

a b

TS 3.1-23a 0629-06 (3)

During the initial 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , maintain a bubble in the pressurizer with a maximum narrow range level of 33%,

or (4)

Maintain two Power Operated Relief Valves (PORV) OPERABLE with a lift setting of ~ 390 psig and verify each PORV block valve is open at least y

once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or (5)

The RCS shall be vented through one open PORV or an equivalent size as sfleeified eels'll:

flath is SfleH at least SHee fleF 12 hSHFS, SF (b) with the Res vented thrt't1gh fl It'eked t'peti vetit Pflth..efify the Pflth is open at least t'nee pel 31 dfry s.

One PORV may be inoperable in INTERMEDIATE SHUTDOWN with the RCS average temperature> 200 0P but < 350 0P for a period not to exceed 7 days. If the inoperable PORV is not restored to OPERABLE status within 7 days, then completely depressurize the RCS and vent through one open PORV or an equivalent size opening within the next 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

One PORV may be inoperable in COLD SHUTDOWN or REFUELING SHUTDOWN with the reactor vessel head bolted for a period not to exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If the inoperable PORV is not restored to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months then completely depressurize the RCS and vent through one open PORV or an equivalent size opening within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Amendment Nos. 248 and 247

in accordance with the frequency specified in the Surveillance Frequency TS 3.12-4 Control Program.

03-02-~4

2. Prior to ~5% of RATED POWER following each core loading and

-1,

~~.

£ __ 11

.~t.

..c'

~.

power distribution

.1.\\..1..1..1. r

..L maps using the movable detector system shall be made to confirm that the hot channel factor limits of this specification are satisfied. For the purpose of this confirmation:

a.

The measurement of total peaking factor p Meas shall be increased by eight Q

percent to account for manufacturing tolerances, measurement error and the effects of rod bow. The measurement of enthalpy rise hot channel factor pN

~H shall be compared directly to the limit specified in Specification 3.12.B.1. If any measured hot channel factor exceeds its limit specified under Specification 3.12.B.1, the reactor power and high neutron flux trip setpoint shall be reduced until the limits under Specification 3.12.B.1 are met. If the hot channel factors cannot be brought to within the PQ(Z) and P~H limits as t specified in the CORE OPERATING LIMITS REPORT within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the Overpower ~T and Overtemperature ~T trip setpoints 'shall be similarly reduced within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

.'P

b. 'The provisions of Specification 4.0.4 are not applicable.

3. The reference equilibrium indicated axial flux difference (called the target flux difference) at a given power level Po is that indicated axial flux difference with the core in equilibrium xenon conditions (small or no oscillation) and the control rod assemblies more than 190 steps withdrawn. The target flux difference at any other power level P is equal to the target value at Po multiplied by the ratio PlPo. The target flux difference shall be measure at h~ast SHO@ f>@f @qaival@Ht fall f>SW@[

qaart@[. The target flux difference must e updated during each effective full power month of operation either by actual easurements or by linear interpolation using the most recent value and the va e predicted for the end of the cycle life. The provisions of Specification 4.0.4 are not applicable.

4. Except as modified by Spe 'fications 3.12.B.4.a, b, c, or d below, the indicated axial flux difference shall e maintained within a +/- 5% band about the target flux difference (defines the t get band on axial flux difference).

in accordance with the frequency specified in the Amendment Nos. 189 title 189 Surveillance Frequency Control Program.

TS 3.12-6 02-04-94 (1) The indicated axial flux difference may deviate from its target band.

(2) A power increase to a level greater than 50 percent of RATED POWER is contingent upon the indicated axial flux difference not being outside its target band for more than one hour accumulated penalty during the preceding 24-hour period. One half minute penalty is accumulated for each one minute of operation outside of the target band at power levels between 15% and 50% of RATED POWER.

d.

The axial flux difference limits for Specifications 3.12.BA.a, b, and c may be suspended during the performance of physics tests provided:

POWER, and (1) The power level is maintained less than or equal to 85% of RATED f (2) The limits of Specification 3.12.B.l are maintained. The power level shall be determined to be less than or equal to 85% of RATED POWER at least If' in accordance with the once per hour during physics tests. Verification that the limits of frequency specified in the Surveillance Frequency ation 3.12.B.1 are being met shall be demonstrated through in-core Control Program.

flux mapping at least "nee per 12 hUUlS.

Alarms shall normally be used to indicate the deviations from the axial flux difference requirements in Specification 3.12.BA.a and the flux difference time limits in Specifications 3.12.BA.b and c. If the alarms are out of service temporarily, the axial flux difference shall be logged and conformance to the limits assessed every hour for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and half-hourly thereafter. The indicated axial flux difference for each excore channel shall be monitored at least once per 7 days when the alarm is OPERABLE and at least once per hour for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after restoring the alarm to OPERABLE status.

Amendment Nos. 186 anel186

TS 3.12-9 06-2~-O~

(a) power shall be reduced to less than 75% of RATED POWER within one (1) hour, and the High Neutron Flux trip setpoint shall be reduced to less than or equal to 85% of RATED POWER within the next four (4) hours, or (b) the remainder of the control rod assemblies in the group with the inoperable control rod assembly are aligned to within 12 steps of the inoperable rod within one (1) hour while maintaining the control rod assembly sequence and insertion limits specified in the CORE OPERATING LIMITS REPORT; the THERMAL POWER level shall be restricted pursuant to Specification 3.12.A during subsequent operation.

2) the shutdown margin requirement of Specification 3.12.A.3.c is determined to be met within one hour and at leflst 6ftee per 12 ft6t1rS tfterefl'ftel.

If\\.

3) the hot channel factors are shown to be within the design limits of Specification 3.12.B.1 within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

~urther, it shall be demonstrated that the value of FxyCZ) used in the Cons ant Axial Offset Control analysis is still valid.

4) a reevaluation of each accident analy is of Table 3.12-1 is performed within 5 days. This reevaluation shall onfirm that the previous analyzed results of these accidents remain valid or the duration of operation under these conditions.

in accordance with the frequency

'- specified in the Surveillance Frequency Control Program.

Amendment Nos. 263 and 264

in accordance with the frequency specified in the Surveillance Frequency Control Program.

be within their limits aHleftt~ffiee-e¥el~~~IfS.

TS 3.12-12A 06-25-09

b. The Reactor Coolant System Tot Flow Rate shall be determined to be within its limit by measurement at least OH:ee f'ef feftleling e,de.

2.

When any of the parameters in Specification 3.12.F.l has been determined to exceed its limit, either restore the parameter to within its limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than 5% of RATED POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

3.

The limit for Pressurizer Pressure in Specification 3.12.F.l is not applicable during either a THERMAL POWER ramp increase in excess of 5% of RATED POWER per minute or a THERMAL POWER step increase in excess of 10% of RATED POWER.

G.

Shutdown Margin 1.

Whenever the reactor is subcritical, the shutdown margin shall be within the limits specified in the CORE OPERATING LIMITS REPORT. If the shutdown margin is not within limits, within 15 minutes, initiate boration to restore shutdown margin to within limits.

Amendment Nos. 265 ElH:El264

TS 3.12-20 060796 A 2% QUADRANT POWER TILT allows that a 5% tilt might actually be present in the core because of insensitivity of the excore detectors for disturbances near the core center such as misaligned inner control rod assembly and an error allowance. No increase in FQoccurs with tilts up to 5% because misaligned control rod assemblies producing such tilts do not extend to the unrodded plane, where the maximum FQoccurs.

The QPTR limit must be maintained during power operation with THERMAL POWER> 50% of RATED POWER to prevent core power distributions from exceeding the design limits.

Applicability during power operation ~ 50% RATED POWER or when shut down is not required because there is either insufficient stored energy in the fuel or insufficient energy being transferred to the reactor coolant to require the implementation of a QPTR limit on the distribution of core power. The QPTR limit in these conditions is, therefore, not important. Note that the FN~H and FQ(Z) LCOs still apply, but allow progressively higher peaking factors at 50%

RATED POWER or lower.

The limits of the DNB-related parameters assure that each of the parameters are maintained within the normal steady-state envelope of operation assumed in the transient and accident analyses. The limits are consistent with the UFSAR assumptions and have been analytically demonstrated to be adequate to maintain a minimum DNBR which is greater than the design limit throughout each analyzed transient. Measurement uncertainties are accounted for in the DNB design margin. Therefore, measurement values are compared directly to the surveillance limits without applying instrument uncertainty.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months periodic surveillance of temperature and pressure through instrument readout is sufficient to ensure that these parameters are restored to within their limits following load changes and other expected transient operation. The measurement of the Reactor Coolant System Total Flow Rate ofteeper reftleliftgeyele is adequate to detect flow degradation.

in accordance with the frequency specified in the Surveillance Frequency Control Program.

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.

Amendment Nos. 210 and 210

TS 3.16-2 040505

4. Two physically independent circuits from the offsite transmission network to energize the 4,160V and 480V emergency buses. One of these sources must be immediately available (i.e. primary source) and the other must be capable of being made available within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (i.e. dependable alternate source).

5. Two OPERABLE flow paths for providing fuel to each diesel generator.

6. Two station batteries, two chargers, and the DC distribution systems OPERABLE.

7. Emergency diesel generator battery, charger and the DC control circuitry OPERABLE for the unit diesel generator and for the shared back-up diesel generator.

at the frequency specified in the Surveillance Frequency Control Program B. During POWER OPERATION or the return to power from H T SHUTDOWN, the J

requirements of specification 3.l6-A may be modified by one the following:

l.a.

With either unit's dedicated diesel generator or share backup diesel generator unavailable or inoperable:

1.

2.

3.

Verify the operability of two physically in endent offsite AC circuits within one hour and at least oaee }'ler eigHt HOl:lfS tkefeafter.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , determine that the OPERABLE diesel generator is not {

inoperable due to common cause failure or demonstrate the operability of the remaining OPERABLE diesel generator by performing Surveillance Requirement 4.6.A.l.a. For the purpose of operability testing, the second diesel generator may be inoperable for a total of two hours per test provided the two offsite AC circuits have been verified OPERABLE prior to testing.

If this diesel generator is not returned to an OPERABLE status within 7 days, the reactor shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

l.b.

One diesel fuel oil flow path may be "inoperable" for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months provided the other flow path is proven OPERABLE. If after 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the inoperable flow path cannot be returned to service for reasons other than buried fuel oil storage tank inspection and related repair, the diesel shall be considered "inoperable."

When the emergency diesel generator battery, charger or DC control circuitry is inoperable, the diesel shall be considered "inoperable."

Amendment Nos. 241ltftB 240

TS 3.16-3 07'-220li 2.

If a primary source is not available, the unit may be operated for seven (7) days provided the dependable alternate source can be OPERABLE within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . If specification A-4 is not satisfied within seven (7) days, the unit shall be brought to COLD SHUTDOWN.

3.

One battery may be inoperable for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months provided the other battery and battery chargers remain OPERABLE with one battery charger carrying the DC load of the failed battery's supply system. If the battery is not returned to OPERABLE status within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period, the reactor shall be placed in HOT SHUTDOWN. If the battery is not restored to OPERABLE status within an additional 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , the reactor shall be placed in COLD SHUTDOWN.

4.

One buried fuel oil storage tank may be inoperable for 7 days for tank inspection and related repair, provided the following actions are taken:

a.

prior to removing the tank from

service, verify that 50,000 gallons of replacement fuel oil is available offsite and transportation is available to deliver that volume of fuel oil within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , and b.

prior to removing the tank from service and at least 6f1:ee evefY 12 ft6l:lfS, verify that the remaining buried fuel oil storage tank co ins 2 17,500 gallons, and c.

prior to removing the tank from service a:fttTftl~Itst-'6fI:;~~~+i:-~IiTS,verify that the above ground fuel oil storage tank contains 2 5 If these conditions are not satisfied or if the buried uel il storage tank is not returned to OPERABLE status within 7 days, both unr s hall be placed in HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD TDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

C. The continuous running electrical load supplied by an em gency diesel generator shall be limited to 2750 KW.

at the frequency specified in the Basis Surveillance Frequency Control Program The Emergency Power System is an on-site, independent, automatically starting power source. It supplies power to vital unit auxiliaries if a normal power source is not available. The Emergency Power System consists of three diesel generators for two units. The Unit 1 diesel generator and the Unit 2 diesel generator are dedicated to emergency buses IH and 2H, respectively. A third diesel generator is provided as a "swing diesel" and is shared by Units 1 and 2. Upon receipt of a safety injection signal on a unit, the shared diesel generator automatically aligns to either emergency bus 11 (Unit 1) or 2J (Unit 2) as a backup power supply for the accident unit. The shared diesel is configured to preferentially load to the Unit 2 emergency bus on a loss of offsite power without a safety injection signal. The Unit 1 and Unit 2 diesel generators also supply power for certain common or shared plant systems/components. The diesel generators have a cumulative 2,000 hour0 days 0 hours 0 weeks 0 months rating of 2750 KW. The actual loads are verified by engineering calculation to remain below the 2750 kw limit.

Amendment Nos. Bases-

TS 4.1-1 07-15-05 4.1 OPERATIONAL SAFETY REVIEW Applicability Applies to items directly related to safety limits and limiting conditions for operation.

Objective and at the frequencies specified in the Surveillance Frequency Control Program, unless otherwise noted in the Tables.

Specification To specify the minimum frequency and type of surveillance to be applied to unit equipment and conditions.

A. Calibration, testing, and checking of instrumentation channels and. terlocks shall be performed as detailed in Tables 4.1-1, 4:-i-=A; and 4.1-2..

~4.1-1A I B. Equipment tests shall be performed as detailed in Table 4.l-2.A and as detailed below.

1. In addition to the requirements of the Inservice Testing Program, each Pressurizer

.-r PORV and block valve shall be demonstrated OPERABLE by:

a.

Performing a complete cycle of each PORV with the re tor coolant average temperature >350 oP once pel 18 ffi6fttHS.

b.

Performing a complete cycle of the solenoid air control alve and check valves on the air accumulators in the PORV control system ~~'et'"~-fI:'l:C**B:s c.

Operating each block valve through one complete cycl of travel at least 6ftee per 92 da,s. This surveillance is not required if the blo k valve is closed in accordance with 3.1.6.a, b, or c.

d.

Verifying that the pressure in the PORV backup air su ply is greater than the surveillance limit at least 6ftee per 92 dfry s.

e.

Performing functional testing and calibration of the P RV backup air supply instrumentation and alarm setpoints -at-:tea:rt-tmC1e-'p1er-:tJt1monttliS',

at the frequencies specified in the Surveillance Frequency Control Program Amendment Nos. 243 and 242

TS 4.1-1a 05-02-95

2. The pressurizer water volume shall be determined to be within its limit as defined in Specification 2.3.A.3.a at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months whenever the reactor is not subcritical by at least 1% Ak/k,

3. Each Reactor Vessel Head vent path remote operating isolation valve not required to be closed by Specification 3.1.A.7a or 3.1.A.7b shall be demonstrated OPERABLE at each COLD SHUTDOWN but not more often than once per 92 days by operating the valve through one complete cycle of full travel from the control room.

4.

Each Reactor Vessel Head vent path shall be demonstrated OPERABLE following each refueling by:

a.

Verifying the manual isolation valves in each vent path are locked in the open position.

b.

Cycling each remote operating isolation valve through at least one complete cycle of full travel from the control room.

c.

Verifying flow through the reactor vessel head vent system vent paths.

C. Sampling tests shall be conducted as detailed in Table 4.1-2B.

D. Whenever containment integrity is not required, only the Table 4.1-1 and 4.1-2A and 4.1-2B are applicable.

E. Flushing of wetted sensitized statinless steel pipe s tions as identified in the Basis Section shall be conducted only if the RWST W er Chemistry exceeds 0.15 PPM chlorides and/or fluorides (CL-and or P-). Flu ing of sensitized stainless steel pipe sections shall be conducted as detailed in T and at the frequencies specified in the Surveillance Frequency Control Program, unless otherwise noted in the Table.

Amendment Nos. 199 aHcl198

lea5t once pet 31 day 5.

TS 4.1-1b 01-22-93 F. Containment Ventilation Purge System isolation valves:

1. The outside Containment Ventilation Purge System isolation valves and the isolation valve in the containment vacuum ejector suction line outside containment shall be determined locked, sealed, or otherwise secured in the closed positio at the frequency specified in the Surveillance 2.

The inside Containment V Frequency Control Program.

isolation valve in the containment vacuum ejector suction line inside containment shall be verified locked, sealed, or otherwise secured in the closed position each COLD SHUTDOWN, but not required to be verified more than once per 92 days.

G. Verify that each containment penetration not capable of being closed by OPERABLE automatic isolation valves and required to be closed during accident conditions is closed by manual valves, blind flanges, or deactivated automatic valves secured* in the closed position at Ieess SHes }3@f31 days. Valves, blind flanges, and deactivated automatic or manual valves cated inside containment which are locked, sealed, or otherwise secured in the close osition shall be verified closed during each COLD SHUTDOWN, but not required to e verified more than once per 92 days.

the frequency specified in the Surveillance Frequency Control Program.

Non-automatic or deactivated automatic valves may be opened on an intermittent basis under administrative control. The valves identified in TS 3.8;A.2 and TS 3.8.A.3 are excluded from this provision.

Amendment Nos. 172 ftftel 171

TS 4.1-3 05-31-06 Other channels are subject only to the "drift" errors induced within the instrumentation itself and, consequently, can tolerate longer intervals between calibration. Process systems instrumentation errors resulting from drift within the individual instruments are normally negligible.

During the interval between periodic channel tests and ~ check of each channel, a comparison between redundant channels will reveal any abnormal condition resulting from a calibration shift, due to instrument drift of a single channel.

During the periodic channel test, if it is deemed necessary, the channel may be tuned to compensate for the calibration shift. However, it is not expected that this will be required at any fixed or frequent interval.

THt:lS, ffliftifflt:lffl ealiaratioft freEj:HeHeies of OHG@ p@f Gay fQf tR.@ QlH;1@ar flyx (I'thveI level) ehfinnel~, find ~nee per 18 m~nths for the pr~cess system channels are eoftsiaerea aeeefltable.

Testing The OPERABILITY of the Re ctor Trip System and ESFAS instrumentation systems and interlocks ensures th

1) the associated ESF action and/or reactor trip will be initiated when the parame r monitored by each channel or combination thereof exceeds its setpoint, 2) the specified coincidence logic and sufficient redundancy are maintained to permit channel to be out of service for testing or maintenance consistent with maintaini an appropriate level of reliability of the RTS and ESFAS instrumentation, and 3) sufficient system functional capability is available from diverse parameters.

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.

Amendment Nos. 247 aHG 246

TS 4.1-4 08-31-01 The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability. Speeifie sUfveillftHee iHtefvals and sur veilhtnee llnd mllintenllnee ~utllge times hllve been determined in lleeordllnee

'Nidi WCAP 10271, EVALUATION OP SURVEILLANCE PREQUENCIES AND OUT OF SERVICE TIMES FOR TIlE REACTOR TRIP INSTRUMm~TATIOf~SYSTEM, and supplements to thatrepOlt, ViCAP-10271 Supplement 2, EVALUATION OF SURVEILLANCE FREQUENCIES AND OUT OF SERVICE TIMES FOR TIlE m~OINEEREDSAFETY FEATURES ACTUATIOf~SYSTEf9i, and supplements to that repOlt, and WCAP-14333P, PltOBABILISTIC RISK ANALYSIS OF TIlE RPS AND ESF TEST TIMES AND COMPLETION TIMES, as appIOvedby the N'ltC and documented in SElts ElateEl Pel:)fURi'~r 21, 1985, Pe6ftHtfY 22, 1989, the SSER dttted April 30, 1990 ~r WCAP-10271 and July 15, 1998 fOl WCAP-14333P. Fur those funeti~n1l1 units Het iHeh:1ded iH the geHerie WestiHgheuse l'fefl8:flilistie fisk 8:H8:lyses Eliseussed fibe. e, 8: 1'18:Ht sl'eeifie fisk assessment Vias fleFf'eFmeEl. THis Fisk aSS8SSI+l8At Elemenstfates taat tae effeet en eefe Elamage fFeE1tieney anEl iHerementa1 eaange in e~re dllmllge pr~bllbilit, is negligible for the relllxllti~ns llss~eillted with the 8:dditieHB:l ftmetieH8:1 UHitS.

Surveillance testing of instrument channels is routinely performed with the channel in the tripped condition. Only those instrument channels with hardware permanently installed that permits bypassing without lifting a lead or installing a jumper are routinely tested in the bypass condition. However, an inoperable channel may be bypassed by lifting a lead or installing a jumper to permit surveillance testing of another instrument channel of the same functional unit.

Amendment Nos. 228 find228

TS 4.1-5 102909 The refueling water storage tank is sampled weekly for Cl ' and/or F-contaminations. Weekly sampling is adequate to detect any inleakage of contaminated water.

Main Control Room/Emergency Switchgear Room (MCR/ESGR) Envelope Isolation Actuation Instrumentation The MCR/ESGR Envelope Isolation Actuation function provides a protected \\

environment from which operators can control the unit following an uncontrolled release of radioactivity. A functional check of the Manual Actuation function is performe 18 ffl6ftths. The test freqaency is based 011 dIe known reli::rbiliry

-tm'6tl~""6f~MtI:tg""~pe:r'te:ltee. The Surveillance Requirement will ensure that the two trains f the MCR/ESG envelope isolation dampers close upon manual actuation 0 the MCR/ESGR velope Isolation Actuation Instrumentation and that the su ply and exhaust ans in the normal ventilation system for the MCR/ESG envelope shut do n, as well as adjacent area ventilation fans.

Automatic ctuation of the CR/ESGR Envelope Isolation Actuation Instrumentati n is confirmed as p rt of the Logic Channel Testing for the Safety Injection syste at the frequenc specified in the Surveillance Frequency Control The safety-related, seismic POR backup air supply is relied upon for two functions - mitigation of a design bas s steam generator tube rupture accident and low temperature overpressure prote tion (LTOP) of the reactor vessel during startup and shutdown. The surveillanc criteria are based upon the more limiting requirements for the backup air sup ly (i.e. more PORV cycles potentially required to perform the mitigation funct n), which are associated with the LTOP function.

The PORV backup air supply system is p ovided with a calibrated alarm for low air pressure. The alarm is located in the c ntrol room. Failures such as regulator drift and air leaks which result in low pres re can be easily recognized by alarm or annunciator action. A periodic quarterly erification of air pressure against the surveillance limit supplements this type f built-in surveillance. Based on experience in operation, the minimum chec g frequencies set forth are deemed ade uate.

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.

Amendment Nos. 266 and 265

Replace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" TABLE 4.1-1 CALIBRATIONS AND lEST OF INSTRUMENT CHANNELS Chec(

CaliJ'ate

~

Channel Description Test Remarks 1.

Nuclear Power Range

-S-

"17(1,5) i!(2) 1)

Against a heat balance standard, above 15% RATED POWER

~3,5) 2)

Signal a! LlT; bistable action (permissive, rod stop, trip)

R(4) 3)

Upper and lower chambers for symmetric offset by means of the movable incore detector system 4)

Neutron detectors may be excluded from CHANNEL CALIBRATION 5)

The provisions of Specification 4.0.4 are not applicable 2.

Nuclear Intermediate Range

*(2,3)

P(l) 1)

Log level; bistable action (permissive, rod stop, trip)

(below P-I0 setpoint) 2)

Neutron detectors may be excluded from CHANNEL CALIBRATION 3)

The provisions of Specification 4.0.4 are not applicable 3.

Nuclear Source Range

5

'R(2,3)

P(l) 1)

Bistable action (alarm, trip)

(below P-6 setpoint) 2)

Neutron detectors may be excluded from CHANNEL CALIBRATION 3)

The provisions of Specification 4.0.4 are not applicable 4.

Reactor Coolant Temperature

8-

-R-

-EZ(l) 1)

Overtemperature LlT

~(2) 2)

Overpower LlT 5.

Reactor Coolant Flow

""S-it

~

6.

Pressurizer Water Level

-S-

-R-i!

~

7.

Pressurizer Pressure

-g-

"it".

-fZ

s0-(High & Low)

~

s 8.

4 KV Voltage and Frequency N.A.

R-

-tt(l) 1)

Setpoint verification not required Z

9.

Analog Rod Position

8(1,2)

"it""

N.A.

1)

With step counters l~

0:"

(3) 2)

Each six inches of rod motion when data logger is out of service 3)

N.A. when reactor is in HOT, INTERMEDIATE OR COLD SHUTDOWN

Replace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP"

.1-Continued)

MINIMUMFRE RA IONS AND TEST OF INSTRUMENT CHANNELS Channel Description Check Calibrate Test Remarks

23. Turbine First Stage Pressure

-s

-a

~

..-r

24. Deleted 4"

25. Deleted

..-r

26. Logic Channel Testing N.A.

N.A.

M(l)(2)

1) Reactor protection, safety injection and the consequence limiting safeguards system logic are tested monthly per this line item.

2) The master and slave relays are not included in the monthly logic channel test of the safety injection system.

27. Deleted

-r

28. Turbine Trip Setpoint verification is not applicable A. Stop valve closure N.A.

N.A.

P B. Low fluid oil pressure N.A.

N.A.

P 29.

Deleted

....r 30.

Reactor Trip Breaker N.A.

N.A.

-M The test shall independently verify operability ofthe 3

(1) undervoltage and shunt trip attachments 0-

~

31. Deleted

+-

Z 0:n u

Replace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" Remarks The test shall independently verify the operability of the undervoltage and shunt trip attachments for the manual reactor trip function. The test shall also verify the operability of the bypass breaker trip circuit.

1) Remote manual undervoltage trip immediately after placing the bypass breaker into service, but prior to commencing reactor trip system testing or required maintenance.

2) Automatic undervoltage trip.

1) Setpoint verification not required.

~1)

t M(1),

""1t(2)

N.A.

-R-

"it N.A.

N.A.

l-\\(Continued)

RAtIONS AND TEST OF INSTRUMENT CHANNELS

-S-it (Z(l)

1) The auto start ofthe turbine driven pump is not included in the quarterly test, but is tested within 31 days prior to

,-r each startup.

it" it(1)(2)

1) The actuation logic and relays are tested within 31 days prior to each startup.

2) Setpoint verification not required.

(All Safety Injection surveillance requirements)

N.A.

R-N.A.

N.A.

oR:'

Check Calibrate Test MINIMUMFRE

b. RCP Undervoltage

c. S.l.

d. Station Blackout

e. Main Feedwater Pump Trip

33. Loss of Power

a. 4.16 KV Emergency Bus Undervoltage (Loss of Voltage)

b. 4.16 KV Emergency Bus Undervoltage (Degraded Voltage)

34. Deleted

35. Manual Reactor Trip Channel Description

32. Auxiliary Feedwater

a. Steam Generator Water Level Low-Low

36. Reactor Trip Bypass Breaker i

~g

~

C/J 37.

Safety Injection Input to RPS 38.

Reactor Coolant Pump Breaker Position Trip N.A.

N.A.

--R-

'it

~

I 00

~

Replace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" u

y Check Consists of verifying for an indicated intake canal level greater than 23'-5.85" that all four low level sensor channel alarms are not in an alarm state.

Calibration Consists of uncovering the level sensor and measuring the time response and voltage signals for the immersed and dry conditions. It also verifies the proper action of instrument channel from sensor to electronics to channel output relays and annunciator. Only the two available sensors on the shutdown unit would be tested.

Tests

1) The logic test verifies the three out of four logic developmentfor each train by using the channel test switches for that train.

2)

Channel electronics test verifies that electronics module responds properly to a superimposed differential millivolt signal which is equivalent to the sensor detecting a "dry" condition.

.1-1 (Continued)

MINIMUMFRE nONS AND TEST OF INSTRUMENT CHANNELS Channel Description Remarks

39. Steam/Feedwater Flow and Low S/G

~

oR

~l)

1) The provisions of Specification 4.0.4 are not applicable Water Level

40. Intake Canal Low (See f"om1,tpte 1)

B-

-R-M(1),

1) Logic Test

~2)

2) Channel Electronics Test

41. Turbine Trip and Feedwater Isolation

a. Steam generator water level high

-S-

-R-

+

b. Automatic actuation logic and N.A.

H:-

M(l)

1) Automatic actuation logic only, actuation relays tested actuation relay each refueling

42. Reactor Trip System Interlocks

a. Intermediate range neutron flux, N.A.

t1)

(2)

1) Neutron detectors may be excluded from the calibration P-6

2) The provisions of Specification 4.0.4 are not applicable.

b. Low reactor trips block, P-7 N.A.

(1)

(2)

c. Power range neutron flux, P-8 N.A.

R(l)

(2)

d. Power range neutron flux, P-10 N.A.

it(l)

R(2)

IMove Footnote 1 to next

e. Turbine impulse pressure N.A.

...p...

'R page

~

I:l

~

I:l.....zo r.n t

Replace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" MINIMUMFRH Channel Description 43.

Engineered Safeguards Actuation Interlocks

a. Reactor trip, P-4

b. Pressurizer pressure, P-ll

c. Low, low Tavg' P-12 N:A.

N.A.

-R-

-R:-

Remarks

..., - Dl1'-U...,UUL D

DlIil, N.A. - Not Applicable Q

E*ery 92 dB.') S

!vi 31 dttys R

Oftee per 18 ffi6fttns frequency specified in the Suveillance Frequency Control Program

-1

~::s

~g Zo (Zl

~

-,- ;:)ee ;:)peCIIlCanOnq-;-r:u SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.

Note 1: Move Footnote 1 from previous page here.

n

Replace each marked through surveillance frequency in the Channel Check, Calibrate, and Functional Test columns with "SFCP" EXPLOSIVE GAS MONITO CHANNEL DESCRIPTION 1.

Waste Gas Holdup System Explosive Gas Monitoring System Oxygen Monitor CHANNEL CHECK

"""'fT CHANNEL CALffiRATION

-Q(l)

CHANNEL FUNCTIONAL TEST

-M j

~tgzo:"

~

channel calibration shall include the use of standard gas samples containing a nominal:

D Daily M-Monthly Q Qttfll1efiy SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.

A Y

y I~

Replace each marked through surveillance frequency in the Channel Check and Calibrate columns with "SFCP" TS 4.1-9a 05-31-06 CH NEL CALIBRATION

-R-

"'it

-R:(2)

"'*(2)

REMENTS CHANNEL CHECK (1)

-M-

--M-

-M-

-M

-M"

-M

-M-

-M Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.

Ne on detectors are excluded from CHANNEL CALIBRATION.

Rather tha HANNEL CALIBRATION, this surveillance shall be an operational test, consisting of verification of rability of all devices in the channel.

M - Moftthl, TABLE 4.1-ACCIDENT MONITORING INSTRUMENTATION SUR R

aftee per 18 rftonth~

INSTRUMENT 1.

Auxiliary Feedwater Flow 2.

Inadequate Core Cooling 3.

Containment Pressure (Wide Range) 4.

Containment Pressure 5.

Containment Sump Water Level (Wide Range) 6.

Containment Area Radiation (High Range) 7.

Power Range Neutron Flux 8.

Source Range Neutron Flux 9.

Reactor Coolant System (RCS) Hot Leg Temperature (Wide Range)

10. RCS Cold Leg Temperature (Wide Range)

11. RCS Pressure (Wide Range)

12. Penetration Flow Path Containment Isolation Valve Position

13. Pressurizer Level

14. Steam Generator (SG) Water Level (Wide Range)

15. SG Water Level (Narrow Range)

16. SG Pressure

17. Emergency Condensate Storage Tank Level

18. High Head Safety Injection Flow to Cold Leg SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.

Amendment Nos. 247 and 246

Replace each marked through surveillance frequency in the Frequency column with "SFCP" MINIMUM FREQUENCY FOR EQUIPMENT:STS FSAR SECTION DESCRIPTION TEST FREQUENCY REFERENCE 1.

Control Rod Assemblies Rod drop times of all full Prior to reactor criticality:

7 length rods at hot conditions a.

For all rods following each removal of the reactor vessel head b.

For specially affected individual rods following any maintenance on or modification to the control rod drive system which could affect the drop time of those specific rods, and c.

Once pel 18 11lonths 2.

Control Rod Assemblies Partial movement of all rods Qt1ttrterly 7

3.

Refueling Water Chemical Addition Functional ORee J3ef 1g ffl8Rfas 6

Tank 4.

Pressurizer Safety Valves Setpoint Per the Inservice Testing Program 4

5.

Main Steam Safety Valves Setpoint Per the Inservice Testing Program 10 6.

Containment Isolation Trip

Functional Once pel 18 months 5

7.

Refueling System Interlocks

Functional Prior to refueling 9.12 8.

Service Water System

Functional OReeJ3ef 1g ffl8Rt;8S 9.9

~

9.

Deleted

==

10.

Deleted

..I-'

0..

~

11.

Diesel Fuel Supply

Fuel Inventory 5 Elaysfweek 8.5

==.....

Z 12.

Deleted 0:"

13.

Main Steam Line Trip Valves Functional Before each startup (TS 4.7) 10 (Full Closure)

The provisions of Specification 4.0.4.

IE are not applicable I

I\\0 cr"

Replace each marked through surveillance frequency in the Freauencv column with "SFCP" TABLE 4.1-2A (CONTINUED)

MINIMUM FREQUENCY FOR EQUIPMENT TESTS DESCRIPTION TEST 14a. Service Water System Valves in Line Functional Supplying Recirculation Spray Heat Exchangers

b. Service Water System Valves Isolating Functional Flow to Non-essential loads on Intake Canal Low Level Isolation

15. MCRlESGR Envelope Isolation Functional Actuation Instrumentation - Manual

16. Reactor Vessel Overpressure Functional & Setpoint Mitigating System (except backup air supply)

CHANNEL CALIBRATION

17. Reactor Vessel Overpressure Setpoint Mitigating System Backup Air Supply

18. Power-Operated Relief Valve Control Functional, excluding valve actuation System CHANNEL CALIBRATION

~

l

~g Zo'"

I FREQUENCY Oftee pel 18 ftl:8fttBS 8nee r5et 1R I\\iBhtftS Oftee pel 18 ftl:8MhS Prior to decreasing RCS temperature below 350°F and monthly while the RCS is <

350°F and the Reactor Vessel Head is bolted Ailce lie) 1R IiltJiltl Oftse pel 18 ftl:8fttBS

Memthl, Onee per 18 montJ:ll; FSAR SECTION REFERENCE 9.9 9.9 9.13 4.3 4.3 4.3

~

u

Replace each marked through surveillance frequency in the Frequency column with "SFCP" SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.

~

g I

I\\D 0..

,f 14 UFSAR SECTION REFERENCE Once pet 1S memths FREQUENCY 1.

Periodic leakage testing(a)(b) on each valve listed in Specification 3.1.C.5.a shall be accomplished prior to entering POWER OPERAnON after every time the plant is placed in COLD SHUTDOWN for refueling, after each time the plant is placed in COLD SHUTDOWN for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if testing has not been accomplished in the preceding 9 months, and prior to returning the valve to service after maintenance, repair or replacement workjs performed.

Semi-Annual (Unit at power or shutdown) if purge valves are operated during intervalec)

Functional TEST Functional Flow ~ 273,000 gpm TABLE 4.1-2A(CONTINUED)

MINIMUM FREQUENCY FOR EQUIPMENT JESTS 20.

Containment Purge MOVLeakage 21.

Deleted 22.

RCS Flow 23.

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

(b)

Minimum differeiiti test pressure shall not be below 150 psid.

(c)

Refer to Section 4.4 for a tance criteria.

See Specification 4.1.D.

DESCRIPTION 19.

Primary Coolant System

>§ tg

~'"

TS 4.1-10 08-15-03 Replace each marked through surveillance frequency in the Frequency column with "SFCP" TABLE 4.1-2B MINIMUM FREQUENCIES FOR SAMPLING TESTS UFSAR SECTION DESCRIPTION TEST FREQUENCY REFERENCE 1.

Reactor Coolant Radio-Chemical Memthly (5)

Liquid Samples Analysis (1)

Gross Activity (2) 5 days/week (5) 9.1 Tritium Activity Vleddy (5) 9.1

Chemistry (CL, F & O2) 5 day~/vyeek (9) 4

Boron Concentration Twiee/neek 9.1 E Determination SemianlltlaHy (3)

DOSE EQUIVALENT 1-131 OnceJ'2 weeks (5)

Radio-iodine Analysis Once/4 hours (6)

(including 1-131, 1-133 &

and (7) below 1-135) 2.

Refueling Water Storage Chemistry (CI & F) ll.'eelcl) 6 3.

Boric Acid Tanks

Boron Concentration TwiecA\\'eek 9.1 4.

Chemical Additive Tank NaOH Concentration Ml"nthly 6

5.

Spent Fuel Pit

Boron Concentration MeFltaly 9.5 6.

Secondary Coolant DOSE EQUIVALENT 1-131 MSFltHly 7.

Stack Gas Iodine and

1-131 and particulate

'vVeekly Particulate Samples radioactive releases

See Specification 4.1.D

(

A radiochemical analysis will be made to evaluate the following corrosion products: Cr-51, Fe-59, Mn-54, Co-58, and Co-60.

2)

A gross beta-gamma degassed activity analysis shall consist of the quantitative measurement of the total radioactivity of the primary coolant in units of f.lCilcc.

SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.

Amendment Nos. 234 and 233

TS 4.1-lOa 08-15-03 Ino change for information only (3) E determination will be started when the gross gamma degassed activity of radionuclides with half-lives greater than 15 minutes analysis indicates ~ 10 /lCi/cc. Routine sample(s) for E analyses shall only be taken after a minimum of 2 EFPD and 20 days of power operation have elapsed since reactor was last subcritical for 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or longer.

(4) Deleted.

(5) When reactor is critical and average primary coolant temperature

~ 350°F.

(6) Whenever the specific activity exceeds 1.0 /lCilcc DOSE EQUIVALENT 1-131 or 100/E /lCi/cc and until the specific activity of the Reactor Coolant System is restored within its limits.

(7) One sample between 2 & 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months following a THERMAL POWER change exceeding 15 percent of RATED POWER within a one hour period provided the average primary coolant temperature ~ 350oP.

(8) Deleted.

(9) Sampling for chloride and fluoride concentrations is not required when fuel is removed from the reactor vessel and the reactor coolant inventory is drained below the reactor vessel flange, whether the upper internals and/or the vessel head are in place or not. Sampling for oxygen concentration is not required when the reactor coolant temperature is below 250 degrees F.

Amendment Nos. 234 and 233

TS 4.5-2, 10 1507

2. By verifying that each motor-operated valve in the recirculation spray flow paths performs satisfactorily when tested in accordance with the Inservice Testing Program.

3. By verifying each spray nozzle is unobstructed following maintenance which could cause nozzle blockage.

In addition to the reauirements of the Inservice Testina Proaram.

C.

ach weight-loaded check valve in the containment spray and outside containment recirculation spray subsystems shall be demonstrated OPERABLE OHse fler 18 months by cycling the valve one complete cycle of full travel and ve fying that each valve opens when the discharge line of the pump is pressurized with r and seats when a vacuum is applied.

evidence of

{

recircu ation spray structural distress or abnormal corrosion.

D. Verify, by visual inspection at the frequency specified in the Surveillance Frequency Control Program Amendment Nos. 255 and 254

TS 4.5-3 Os 11 9&

Basis The flow testing of each containment spray pump is performed by opening the normally closed valve in the containment spray pump recirculation line returning water to the refueling water storage tank. The containment spray pump is operated and a quantity of water recirculated to the refueling water storage tank. The discharge to the tank is divided into two fractions; one for the major portion of the recirculation flow and the other to pass a small quantity of water through test nozzles which are identical with those used in the containment spray headers.

The purpose of the recirculation through the test nozzles is to assure that there are no particulate material in the refueling water storage tank small enough to pass through pump suction strainers and large enough to clog spray nozzles.

Due to the physical arrangement of the recirculation spray pumps inside the containment, it is impractical to flow-test them other than during a unit outage. Flow testing of these pumps requires y the physical modification of the pump discharge piping and the erection of a temporary dike to contain recirculated water. The length of time required to setup for the test, perform the test, and then reconfigure the system for normal operation is prohibitive to performing the flow-test on even the cold shutdown frequency. Therefore, the flow-test of the inside containment recirculation spray pumps will be performed 6ftee I'ef 18 fft6ftt:ftS during a unit outage.

The inside containment recirculation sp ay pumps are capable of being operated dry for approximately 60 seconds without significan y overheating and/or degrading the pump bearings.

During this dry pump check, it can be deter ined that the pump shafts are turning by rotation sensors which indicate in the Main Control R om. In addition, motor current will be compared with an established reference value to ascert in that no degradation of pump operation has occurred.

in accordance with the Inservice Testing Program Amendment Nos. 213 aftd 213

TS 4.5-4 10-15-09 The recirculation spray pumps outside the containment have the capability of being dry-run and flow tested. The test of an outside recirculation spray pump is performed by closing the containment sump suction line valve and the isolation valve between the pump discharge and the containment penetration. This allows the pump casing to be filled with water and the pump to recirculate water through a test line from the pump discharge to the pump casing.

With a system flush conducted to remove particulate matter prior to the installation of spray nozzles and with corrosion resistant nozzles and piping, it is not considered credible that a significant number of nozzles would plug during the life of the unit to reduce the effectiveness of the subsystems. Therefore, an inspection or air or smoke test of the nozzles following maintenance which could cause nozzle blockage is sufficient to indicate that plugging of the nozzles has not occurred.

The spray nozzles in the refueling water storage tank provide means to ensure that there is no particulate matter in the refueling water storage tank and the containment spray subsystems which could plug or cause deterioration of the spray nozzles. The nozzles in the tank are identical to those used on the containment spray headers. The flow test of the containment spray pumps and recirculation to the refueling water storage will indicate any plugging of the nozzles by a reduction of flow through the nozzles.

Periodic inspections of containment sump components ensure that the components are unrestricted and stay in proper operating condition. The 18 month fleqaeney i~ ba~ed em: the Heed to }3erfenH: this sHrveillaHee HHder the eOHditioHS that a}3}3ly dHriHg a HHit oHtage aHd OH the Heed to hav@ aee@ss to th@ loeatioH. 11Hs fF@E):HeHey has BeeH feHHd to Be sHffieieHt to detest aeftofffttl1 degradatioHaHd is eOHfiffHed ByO}3eratiHg eJ(}3erieHee.

References 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.

FSAR Section 6.3.1, Containment Spray Pumps FSAR Section 6.3.1, Recirculation Spray Pumps Amendment Nos. 255 and 254

TS 4.6-1 3-17-72 4.6 EMERGENCY POWER SYSTEM PERIODIC JESTING Applicability Applies to periodic testing and surveillance requirements of the Emergency Power System.

Objective To verify that the Emergency Power System will respond promptly and properly when required.

Specification The following tests and surveillance shall be performed as stated:

A.

Diesel Generators 1.

Tests and Frequencies a.

Manually initiated start of the diesel generator, followed by manual synchronization with other power sources and assumption of load by the diesel generator up to 2750 Kw. This test will be conducte~d"ffli:fflt~ on each diesel generator for a duration of 30 minutes. Normal s tion operation will not be affected by this test.

at the frequency specified in the Surveillance Frequency Control Program

at the frequency specified in the Surveillance --...,

Frequency Control Program TS 4.6-2 03-01 99 b.

Automatic start of each diesel generator, load shedding, and restoration to operation of particular vital equipment, initiated by a simulated loss of off-site power together with a

simulated safety injection sign 1.

Testing will demonstrate load shedding and load sequencing initiated by a simulated loss of off-site power following a simulated engineered safety features signal. Testing will also demonstrate that the loss of voltage and degraded vol age protection is defeated whenever the emergency diesel is the sole source of power to an emergency bus and that this protection is automatically rein tated when the

'¥ diesel output breaker is opened. This test will be conducted emfiftg feaetof shutdown for reftleling to assure that the diesel generator will start and accept load in less than or equal to 10 seconds after the engine starting signal.

2.

Acceptance Criteria c.

Availability of the fuel oil transfer system shall be verified by operating the system in conjunction with the month~t. "=-0----------

. '---iTS 4.6.A.1.a surveillance I d.

Each diesel generator shall be given a thorough inspection QRCEl pElf 1g GlQRthS utilizing the manufacturer's recommendations for this class 0 stand-by service.

at the frequency specified in the Surveillance Frequency Control Program The above tests will be considered satisfactory if all applicable equipment operates as designed.

B.

Fuel Oil Storage Tanks for Diesel Generators 1.

A minimum fuel oil storage of 35,000 gal shall be maintained on-site to assure full power operation of one diesel generator for seven days.

Amendment Nos. 218 find218

TS 4.6-3 06 11 98 The following Tests shall be performed at the frequencies specified in the Surveillance Frequency Control Program:

1.

Tests andlF~'ttfe~cles Station Batteries C.

a/1The specific gravity, electrolytic temperature, cell voltage of the pilot cell in I,.,...M"...e-a-s-u-re----,~

each battery, and the D.C. bus voltage of each battery sRan b@J.+),@:u;Uf@QaRa feeem:lea'vveekly.

, bJ1 Each nronth lbe voltage of each battery cell in each battery s1toll ~. mea_ to 1,.,...tv1"...e-a-s-u-re----,i-/

the nearest 0.01 volts and recorded.

IMeasure Compare d.

the begia.aiAg aRa @Ra sf Hie fest.

on each station battery e.

Dtuiflg the fl6fffilil reftteliflg Sftl:lf6S'NH eaeft eaa:ery shall b@ sHbj@st@a to a

=-....,.,.....__~simulated load test without battery charge he battery voltage and current as a function of time shall be monitored.

IPerform Check the battery 2.

f.

ORS@

fl@f 18 HleMftS connections shall ee efteekea for anti-corrosion coating shall be appli@Q to the interconnections.

Acceptance Criteria tightness an: ~.y I apply a.

Each test shall be considered satisfactory if the new data when compared to the old data indicate no signs of abuse or deterioration.

Amendment Nos. 213 lind 213

TS 4.6-4 06-1P~B b.

The load test in (d) and (e) above shall be considered satisfactory if the batteries perform within acceptable limits as established by the manufacturers discharge characteristic curves.

D.

EMERGENCY DIESEL GENERATOR BATTERIES The following Tests shall be performed at the frequencies 1.

T~STS AND FREQUENCIES specified in the Surveillance Frequency Control Program:

~ The specific gravity, electrolytic temperature, cell voltage of the pilot cell in

':"-:------,~

each battery and the D.C. bus voltage of each battery shaH Be ffieaStllee! a:ne!

recorded weekly.

IMeasure

~ Ea:eh ffi8HtB. the voltage of each battery cell in each battery shall be measured to

":""':""---~

the nearest 0.01 volts aHafee8faed.

c.

Every 3 HleHthsthe specific gravity of each battery cell, the temperature reading r:-:----.,

.;11of every fifth cell, the height of electrolyte of each cell, and the amount of water

~

. added to any cell shB:11 BeffiefiStlfea fiHe! fee6faea.

IMeasure IMeasure d.

OHee}3eF 18 Hl6Hths, efieh BMteIy sha-ll be sH1'l:jet;@Q to a normal load or %

=---:-_--,~ simulated load test without battery charge. The battery voltage and current as a function of time shall be monitored.

on each battery e.

Onee pel 18 ffi8HHtS, connections

~ha:ll be eheeked for tightness and~.r

~anti-COrrOSioncoating shaH be applied to interconnections.

ACCEPTANCE CRITERIA apply Iperform ICheck the battery 2.

a.

Each test shall be considered satisfactory if the new data when compared to the old data indicate no signs of abuse or deterioration.

b.

The load test in (d) above shall be considered satisfactory if the batteries perform within acceptable limits as established by the manufacturers discharge characteristic curves.

Amendment Nos. 213 aHa213

TS 4.6-5 5-10-78 Basis The tests specified are designed to demonstrate that the diesel generators will provide power for operation of essential safeguards equipment. They also assure that the emergency diesel generator system controls and the control systems for the safeguards equipment will function automatically in the event of a loss of normal station service po in the Surveillance Frequency Control Program The testing frequency specified will be often enough to identify and correct any mechanical or electrical deficiency before it can result in a system failure. The fuel supply and starting circuits and controls are continuously monitored and any faults are alarm indicated. An abnormal condition in these systems would be signaled without having to place the diesel generators ay deteriorate with time, but precipitous failure is extremely unlikely. -Fhe-In addition alarms have been provided to indicate low batt ry voltage and low current from t inverters which would make it extremely unlikely that dete ioration would go unnoticed.

The equalizing charge, as recommended by t e manufacturer, is vital to maintaining the ampere-hour capability of the battery. As a check upon the effectiveness of the equalizing charge, the battery shall be loaded rather heavily and the voltage monitored as a function of time. If a cell has The Surveillance Frequencies may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

Unit No.1 Amendment No. 4+

Unit No.2 Amendment No. 4fr"

TS 4.8-1 02-23-06 4.8 AUXILIARY FEEDWATER SYSTEM Applicability Applies to the periodic testing requirements of the Auxiliary Feedwater System.

Objective To verify the operability of the auxiliary feedwater pumps.

Specification The following Tests shall be performed at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted below:

1. At least once PCl 31 day1;.

"ft:" Verify that the Auxiliary Feedwater System manual, power operated, and automatic valves in each flowpath are in the correct position. This verification.r-includes valves that are not locked, sealed, or otherwise secured in position, valves in the cross-connect from the opposite unit and valves in the steam supply paths to the turbine driven auxiliary feedwater pump.

2.

At least aRee fleF 92 days:

1t.

Verify that each motor-operated valve in the auxiliary feedwater flowpaths, l'

including the cross-connect from the opposite unit, performs satisfactorily when tested in accordance with the Inservice Testing Program.

3.

At 1@a8t QRG@fl@F 92 days 8R 8: STAGGERED 'fEST BASIS.

-tt:"'" Verify that the auxiliary feedwater pumps perform satisfactorily when tested in accordance with the Inservice Testing Program.

The provisions of within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after reaching HOT SHUTDOWN.

the developed head test of the turbine driven pump is required to be performed Specification 4.0.4 are not applicable for the tnrbine driven pomp. Note that

~

Amendment Nos. 246 8:ftfl245

TS 4.8-2 02-23 06

4. Whenever the unit's Reactor Coolant System temperature and pressure have been less than 3500P and 450 psig, respectively, for a period greater than 30 days, prior to Reactor Coolant System temperature and pressure exceeding 350 0P and 450 psig, respectively, verify proper alignment of the required auxiliary feedwater flowpaths by verifying flow from the 110,000 gallon above ground Emergency Condensate Storage Tank to the steam generators from each of the auxiliary feedwater pumps.

5. During periods of reactor shutdown with the opposite unit's Reactor Coolant System temperature and pressure greater than 3500P and 450 psig, respectively:

a.

Continue to verify that the motor driven auxiliary feedwater pumps perform satisfactorily when tested at the frequency defined in Specification 4.8.A.3.

b. Verify that each motor-operated valve in the auxiliary feedwater cross-connect flowpath for the opposite unit performs satisfactorily when tested in accordance with the Inservice Testing Program.

Ir:-V:-e-:ri~fy-a-u-:t-o-m-a-:ti:-c-a-c~tu-a~t:-io-n-o~f~:I 6.

OR aR 18 fH8R'ffeEtlieRey:

a.

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

b. ~ ~ch auxiliary feedwater pump starts automatically on an actual or simulated actuation signal. Note that this surveillance is required to be performed for the turbine driven pump within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after reaching HOT SHUTDOWN.

Amendment Nos. 246 nnd 245

TS 4.8-3 0223-06 The correct alignment for manual, power operated, and automatic valves in the Auxiliary Feedwater System steam and water flowpaths, including the cross-connect flowpath, will

..It provide assurance that the proper flowpaths exist for system operation. This position

/1 check does not include: 1) valves that are locked, sealed or otherwise secured in position since they are verified to be in their correct position prior to locking, sealing or otherwise securing; 2) vent, drain or relief valves on those flowpaths; and, 3) those valves that

.;(

cannot be inadvertently misaligned such as check valves. This surveillance does not require any testing or valve manipulation. It involves verification that those valves capable of being mispositioned are in the correct position.

Valves in the auxiliary feedwater flowpaths to he steam generators and cross-connect flow path are tested periodically in accordance ith the Inservice Testing Program. The auxiliary feedwater pumps are tested periodicall in accordance with the Inservice Testing Program to demonstrate operability. Verificati n of the developed head of each auxiliary feedwater pump ensures that the pump p rformance has not degraded. Flow and differential head tests are normal inservice te ting requirements. Because it is sometimes undesirable to introduce cold auxiliary feed ater into the steam generators while they are operating, the inservice testing is typica ly performed on recirculation flow to the 110,000 gallon Emergency Condensate Sto age Tank.

Appropriate surveillance and post-mainte ance testing is required to declare equipment OPERABLE. Testing may not be possib e in the applicable plant conditions due to the necessary unit parameters not having b en established. In this situation, the equipment may be considered OPERABLE provid d testing has been satisfactorily completed to the extent possible, and the equipment is n otherwise believed to be incapable of performing its function. This will allow operatio to proceed to a condition where other necessary surveillance or post maintenance tes can be completed. Relative to the turbine driven auxiliary feedwater pump, Specificati n 4.8.A.3.j< is modified by a note indicating that the developed head test of the turbin driven pump should be deferred until suitable conditions are established; this de erral is required because there may be insufficient steam pressure to perform the test.

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.

Amendment Nos. 246 flfld 245

TS 4.8-4 0223-06 The auxiliary feedwater pumps are capable of supplying feedwater to the opposite unit's steam generators. For a main steam line break or fire event in the Main Steam Valve House, one of the opposite units auxiliary feedwater pumps is required to supply feedwater to mitigate the consequences of those accidents. Therefore, when considering a single failure, both motor driven auxiliary feedwater pumps are required to be OPERABLE* during shutdown to support the opposite unit if the Reactor Coolant System temperature or pressure of the opposite unit is greater than 350°F and 450 psig, respectively. Thus, to establish operability* the motor driven auxiliary feedwater pumps will continue to be tested when the unit is shutdown to support X

in accordance with the Inservice Testina Proaram Proper functioning of the steam turbine admission valve and the ability of the auxiliary feedwater pumps to start will demonstrate the integrity of the system. Verification of correct operation can be made both from instrumentation within the Main Control Room and direct visual observation of the pumps.

The capacity of the Emergenc Condensate Storage Tank and the flow rate of anyone of the three auxiliary feedwater pu ps in conjunction with the water inventory of the steam generators is capable of maintaini g the plant in a safe condition and sufficient to cool the unit down.

excluding automatic initiation instrumentation References UFSAR Section 10.3.1, Main Steam System UFSAR Section 10.3.2, Auxiliary Steam System UFSAR Section 10.3.5, Condensate and Feedwater Systems Amendment Nos. 246 flOe! 245

TS 4.9-1 12-14-n 4.9 RADIOACTIVE GAS STORAGE MONITORING SYSTEM Applicability Applies to the periodic monitoring of radioactive gas storage.

Objective To ascertain that waste gas is stored in accordance with Specification 3.11.

Specification A. The concentration of oxygen in the waste gas holdup system shall be determined to be within the limits of Specification 3.ll.A by continuously monitoring the waste gases in the waste gas holdup system with the oxygen monitor required to be OPERABLE by Table 3.7-5(a) of Specification 3.7.E.

B. The quantity of radioactive material contained in each gas storage tank shall be determined to be within the limits of Specification 3.l1.B.at-te8:St-i:ffi;e;'**,"**'lffiI&-

when the specific activity of the primary reactor coolant is _ 2200 /lCi/gm dose equivalent Xe-133. Under the conditions which result in a spe ific activity

> 2200 /lei/gm dose equivalent Xe-133, the waste gas decay tan s shall be sampled once per day.

at the frequency specified in the Surveillance Frequency Control Program Amendment Nos. 1i1, 1iO

TS 4.10-1 06-25-09 4.10 REACTIVITY ANOMALIES Applicability Applies to potential reactivity anomalies.

Objective To require evaluation of applicable reactivity anomalies within the reactor.

Specification A.

Following a normalization of the computed boron concentration as a function of burnup, the actual boron concentration of the coolant shall be compared ffl8fttkly with the predicted value f the difference between the observed and predicted steady-state concentrations reache the equivalent of one percent in reactivity, an evaluation as to the cause of the discrepancy all be made. The provisions of Specification 4.0.4 are not y applicable.

B.

During periods of POWER OPERATIO at greater than 10% of RATEDPOWER, the hot channel factors identified in Section 3.12sR I be determine deriftg eaek e#eetive fell pm,ver fflt>fttft: of operation using data from limite limits, an evaluation as to the cause of the anomaly Specification 4.0.4 are not applicable.

at the frequency specified in the Surveillance Frequency Control Program Amendment Nos. 265 and 264

TS 4.10-2 122-77 DELETED Basis BORON CONCENTRATION To eliminate possible errors in the calculations of the initial reactivity of the core and the reactivity depletion rate, the predicted relation between fuel burnup and the boron concentration necessary to maintain adequate control characteristics must be adjusted (normalized) to accurately reflect actual core conditions. When full power is reached initially, and with the control rod assembly groups in the desired positions, the boron concentration is measured and the predicted curve is adjusted to this point. As power operation proceeds, the measured boron concentration is compared with the predicted concentration, and the slope of the curve relating burnup and reactivity is compared with that predicted. This process of normalization should be completed after about 10% of the total core bumup. Th reafter, actual boron concentration can be compared with prediction, and the reactivity status of tH core can be continuously evaluated. Any reactivity anomaly greater than I % would be unex cted, and its occurrence would be thoroughly investigated and evaluated.

The value of I% is considered a safe limit sine a shutdown margin of at least I% with the most reactive control rod assembly in the fully withdr wn position is always maintained.

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.

Unit I Amendment No. Unit 2 Amendment No. 3'zt"

TS 4.10-3 12-299 PEAKING FACTORS A thermal criterion in the reactor core design specified that "no fuel melting during any anticipated normal operating condition" should occur. To meet the above criterion during a thermal overpower of 118% with additional margin for design uncertainties, a steady state maximum linear power is selected. This then is an upper linear power limit determined by the maximum central temperature of the hot pellet.

The peaking factor is a ratio taken between the maximum allowed linear power density in the reactor to the average value over the whole reactor. It is of course the average value that determines the operating power level. The peaking factor is a constraint which must be met to assure that the peak linear power density does not exceed the maximum allowed value.

During normal reactor operation, measured peaking factors should be significantly lower than design limits. As core burnup progresses, measured designed peaking factors typically decrease.

A determination of these pettkins faetors dtuins eaeh effeetive fnll power month of operation is aa@E):Hat@ to eRSHre that sore reastivit)' efiaftges v/ith etlfftttp fia ve not sisnifieantl, altered peakins factors iR aft adverse direction.

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.

Unit 1 Amendment No, Unit 2 Amendment No. 34

TS 4.11-1 05 31 95 4.11 SAFETY INJECTION SYSTEM lESTS Applicability Applies to the operational testing of the Safety Injection System.

Objective To verify that the Safety Injection System will respond promptly and perform its design functions, if required.

a.

VeftfYiH~e RWST contained borated w ter volume, and b.

Veftf'iH~e RWST boron conc'f'e"""n'-l:'tr~a~ti..:.:o¥n~

.....,.,,,L......,....,......--.,....---..,:--_.,..,.,...._---L....,

at the frequency specified in the Surveillance Freauencv Control Proaram by:

At leftst 6HeeJ3ef day by}rifying the RWST solution temperat VerifYing: ~

are within specified limits.

At Ie st 6ftee pel ~ b, :

1.

Each safety injection accumulator shall be demonstrated OPERABLE' 2.

is within specified limits.

A.

The refueling water storage tank (RWST) shall be demonstrate OPERABLE:

Specifications B.

[Verifying: ~_

I. ~ loast OAGO po< I~ by:

a.

VerifYiU~e contained borated water volume is withiH s')3@oifi@ElliFn-its, and b.

VerifyiHg nitrogen cover-pressure iB within specifiedlimits.

Amendment Nos. 199 llHd 199

TS 4.11-2 07 15 OS b.

a.

tie boron concentration of the accumulator solution is within specified limits, and 2.

within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each sol tion volume I Increase of greater than or equal to 1% of tank volume y 'lerifyiHg e

boron concentration of the accumulator solution. /2' INote: ~ /.

This surveillance is not required when the volume increase makeup source is the RWST.

C.

Each Safety Injection Subsystem shall be demonstrated OPERABL 1.

-By-~rifYing, that on.recirculation flow, each low head safety inje tion pump performs satisfactorily when tested in accordance with the Inservi e Testing Program.

2.

"tiy~rifying that each charging pump performs satisfactorily when t sted in accordance with the Inservice Testing Program.

3.

-By~ifying that each motor-operated valve in the safety injection flo path performs satisfactorily when tested in accordance with the Inservice Tes ing Program.

at the frequency specified in the 4.

Prior to POWER OPERATION-ey:

Surveillance Frequency Control Program unless otherwise noted below by a.

Verifying that the following motor operated valves are blocked open by de-energizing AC power to the valves motor operator and tagging the breaker in the off position:

MOV-1890C MOV-2890C b.

Verifying that the following motor operated valves are blocked closed by de-energizing AC power to the valves motor operator and the breaker is locked, sealed or otherwise secured in the off position:

Unit 1 MOV-1869A MOV-1869B MOV-1890A MOV-1890B Unit 2 MOV-2869A MOV-2869B MOV-2890A MOV-2890B Amendment Nos. 243 find 242

TS 4.11-3 10 1507 c.

Power may be restored to any valve or breaker referenced in Specifications 4.11.C.4.a and 4.11.C.4.b for the purpose of testing or maintenance provided that not more than one valve has power restored at one time, and the testing and r::-:--=--:----=maintenance is completed and power removed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

IVerifying: ~

5.

Once pel 1BIl1<'IlthS by.

a.

Veri~liQg that each automatic valve capable of receiving a safety injection signal, actuates to its correct position upon receipt of a safety injection test signal. The charging and low head safety injection pumps may be immobilized for this test.

b.

V@rifyiQg that each charging pump and safety injection pump circuit breaker actuates to its correct position upon receipt of a safety injection test signal. The charging and low head safety injection pumps may be immobilized for this test.

Basis c.

VeFifyiftg by visual inspection that the low head safety injection containment sump components are not restricted by debris and show no evidence of structural distress or abnormal corrosion.

Complete system tests cannot be performed when the reactor is operating because a safety injection signal causes containment isolation. The method of assuring operability of these systems is therefore to combine system tests to be performed during unit outages, with more frequent component tests, which can be performed during reactor operation.

Amendment Nos. 255 and 254

TS 4.11-4 10-15-07 The system tests demonstrate proper automatic operation of the Safety Injection System. A test signal is applied to initiate automatic operation action and verification is made that the components receive the safety injection signal in the proper sequence. The test may be performed with the pumps blocked from starting.

The test demonstrates the operation of the valves, pump circuit breakers, and automatic circuitry.

During reactor operation, the instrumentation which is depended on to initiate safety injection is checked periodically, and the initiating circuits are tested in accordance with Specification 4.1. In addition, the active components (pumps and valves) are to be periodically tested to check the operation of the starting circuits and to verify that the pumps are in satisfactory running order. The test interval is determined in accordance with the Inservice Testing Program. The accumulators are a passive safeguard.

UFSAR Section 6.2, Safety Injection System Periodic inspections of containment sump components ensure that the components are unrestricted and stay in proper operating condition. The 1S melfttil ffeEJ:tleH6Y is References 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.

Amendment Nos. 255 aHa254

TS 4.12-1 06-11-~~

4.12 AUXILIARY VENTILATION EXHAUST FILTER TRAINS Applicability Applies to the testing of safety-related air filtration systems.

Objective To verify that leakage efficiency and iodine removal efficiency are within acceptable limits.

Specifications The following Tests shall be performed at the

~---,frequenciesspecified in the Surveillance Frequency Control Program and as required for the conditions identified below:

l.pch redundant filter train circuit shall 13e 0flera£ea e¥ery tHOtt£ft if it has fl:ot l"""'O-p-e-ra-t-e"""'j-I1a-lreaa)' Beeftift of3era£ioa.

2.

Once pel 18 tnOft£ftS, the operability of the entire safety-related portion of the

.-r IDemonstrate~auxiliary ventilation ~aH Be aeffiOfl:stffltea.

3.

~xiliary ventilation system exhaust fan flow rate through each filter train in the IDetermine ~LOCA mode of operation sHall Be aetefffiined initially, after any structural maintenance on the HEPA filter or charcoal adsorber housings, once per 18 months, or after partial or complete replacement of the HEPA filters of charcoal adsorbers.

t The procedure for determining the air flow rate shall be in accordance with Section 9 of the ACGIH Industrial Ventilation document and Section 8 of ANSI N51O-l975.

4...t visual inspection of the filter train and associated components shall be

-=-~~~~ OORa1:l0£ea before each in-place air flow distribution test, DOPtest, or activated charcoal adsorber leak test in accordance with the intent of Section 5 of ANSI IConduct N51O-l975.

Amendment Nos. 213 and 213

TS 4.12-2 05 14-01

5. tf,n air distribution test across the prefilter bank SftB:U ae flerferffi@d initially and Iperform ~ after any major modification, major repair, or maintenance of the air cleaning system affecting the filter bank flow distribution. The air distribution test shall be performed with an anemometer located at the downstream side and at the center of each carbon filter.

6. iplace cold nop tests for HEPA filter banks shft11 be peIf~lmed:

Iperform ~

a.

Initially; b.

Once per 18 months; c.

Following painting, fire, or chemical release in any ventilation zone communicating with the system during system operation;

d. After each complete or partial replacement of the HEPA filter cells; and e.

After any structural maintenance on the filter housing.

The procedure for in-place cold DOl" tests shall be in accordance with ANSI N51O-1975, Section 10.5 or 11.4. The flow rate during the in-place cold nop tests shall be 36,000 CFM +/-1O percent. The flow rate shall be determined by recording the flow meter reading in the control room.

7. "--place halogenated hydrocarbon leakage tests for the charcoal adsorber bank Iperform ~ shall be performed:

a.

Initially; b.

Once per 18 months; Amendment Nos. 225 and 225

TS 4.12-1 06-11-~8 4.12 AUXILIARY VENTILATION EXHAUST FILTER TRAINS Applicability Applies to the testing of safety-related air filtration systems.

Objective To verify that leakage efficiency and iodine removal efficiency are within acceptable limits.

Specifications The following Tests shall be performed at the

~~-,frequencies specified in the Surveillance Frequency Control Program and as required for the conditions identified below:

l.~h redundant filler. train circnit,btilllJo 01""""" "'Of)' _

> it It" ftO' IOperate ~ ~ady aeeft 1ft 0flefaB: Oft.

2. Once pet 18 HiOfttflS, the operability of the entire safety-related portion of the l' IDemonstrate~auxiliary ventilation ~ttll be deHi6flstraJed.

3.

~xiliary ventilation system exhaust fan flow rate through each filter train in the IDetermine I--1'LOCA mode of operation sHall be detennined initially, after any structural maintenance on the HEPA filter or charcoal adsorber housings, once per 18 months, or after partial or complete replacement of the HEPA filters of charcoal adsorbers.

The procedure for determining the air flow rate shall be in accordance with Section 9 of the ACGIH Industrial Ventilation document and Section 8 of ANSI N51O-l975.

4. VA visual inspection of the filter train and associated components shall be r:::--:--':"""""""1~ eOftdHoted before each in-place air flow distribution test, DOP test, or activated charcoal adsorber leak test in accordance with the intent of Section 5 of ANSI IConduct N51O-l975.

Amendment Nos. 213 and 213

TS 4.12-2 05-14-01

5..;f,n air distribution test across the prefilter bank sl.'utll 1ge j3erFofffi@d initially and Iperform ~ after any major modification, major repair, or maintenance of the air cleaning system affecting the filter bank flow distribution. The air distribution test shall be performed with an anemometer located at the downstream side and at the center of each carbon filter.

6. Iplace cold DOP tests for HEPA filter banks shflllbe perftHmeel:

Iperform ~

a.

Initially; b.

Once per 18 months; c.

Following painting,

fire, or chemical release in any ventilation zone communicating with the system during system operation; d.

Aftereach complete or partial replacement of the HEPA filter cells; and e.

After any structural maintenance on the filter housing.

The procedure for in-place cold DOP tests shall be in accordance with ANSI N51O-1975, Section 10.5 or 11.4. The flow rate during the in-place cold DOP tests shall be 36,000 CFM +/-10 percent. The flow rate shall be determined by recording the flow meter reading in the control room.

7. in-place halogenated hydrocarbon leakage tests for the charcoal adsorber bank Iperform ~ shall be performed:

a.

Initially; b.

Once per 18 months; Amendment Nos. 223 and 225

TS 4.12-3 05-14-01 c.

Following painting,

fire, or chemical release in any ventilation zone communicating with the system during system operation; d.

After each complete or partial replacement of charcoal adsorber trays; and e.

After any structural maintenance of the filter housing.

The procedure for in-place halogenated hydrocarbon leakage tests shall be in accordance with ANSI N51O-l975, Section 12.5. The flow rate during the in-place halogenated hydrocarbon leakage tests shall be 36,000 CFM +/-10 percent. The flow rate shall be determined by recording the flow meter reading in the control room.

8. taboratory analysis of each charcoal train slutll be peftefffled:

=---".-----,~ a.

Initially, whenever a new batch of charcoal is nsed to nn adsorbers trays; and IPerform b.

After 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of train operation; and c.

Following painting, fire, or chemical release in any ventilation zone communicating with the system during system operation; and d.

After any structural maintenance on the HEPA filter or charcoal adsorber housings that could affect operation of the charcoal adsorber; and e.

At least once per eighteen months, if not otherwise performed per condition 8.b, 8.c, or 8.d within the last eighteen months.

The procedure for iodine removal efficiency tests shall follow ASTM D3803.

The test conditions shall be in accordance with those listed in Specification 4.l2.B.7.

Amendment Nos. 225 ftnd225

TS 4.12-4 e>6-11-~8

9. The pressure drop across the HEPA filter and adsorber banks shall be checked:

a.

Initially; b.

Once per 18 months thereafter for systems maintained in a standby status and f-after 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation; and c.

After each complete or partial replacement of filters or adsorbers.

B. Acceptance Criteria

1. The minimum period of air flow through the filters shall be 15 minutes p0f H'l8flHt.

2. The system operability test of Specification 4.12.A.2 shall demonstrate automatic start-up, shutdown and flow path alignment.

3. The air flow rate determined in Specification 4.12.A.3 shall be:

a.

36,000 cfm +/-1O percent with system in the LOCA mode of operation.

b.

The ventilation system shall be adjusted until the above limit is met.

4.

Air distribution test across the prefilter-bank shall show uniformity of air velocity within +/- 20 percent of average velocity. The ventilation system shall be adjusted until the limit is met.

Amendment Nos. 213 tlflE1213

at the frequency specified in the Surveillance Frequency Control Program TS 4.12-6 11 08-04 A pressure drop across the combined H 13,PA filters and charcoal adsorbers of less than 7 inches of water at the system design flo w rate will indicate that the filters and adsorbers are not clogged by excessive amounts of preign matter. Operation of the filtration system for a minimum of 15 minutes....

0L revents moisture buildup in the filters and adsorbers.

The frequency of tests and sample analysis of the degradable components of the system, i.e., the HEPA filter and charcoal adsorbers, is based on actual hours of operation to sure that they perform as evaluated. System flow rates and air distribution do not change urr ess the ventilation system is radically altered.

If painting, fire, or chemical release occurs such that the HEPA filter or charcoal adsorber could ecome contaminated from the fumes, chemical, or foreign material, the same tests and sa le analysis are performed as required for operational use.

The in-pl ce test results should indicate a system leak tightness of less than 1 percent bypass lea ge for the charcoal adsorbers and a HEPA efficiency of at least 99.5 percent removal of D P particulates. The heat release from operating ECCS equipment limits the relative humi ity of the exhaust air to less than 80 percent even when outdoor air is assumed to be 1 0 percent relative humidity and all ECCS leakage evaporates into the exhaust air stream Methyl iodide testing to a penetration less than or equal to 14 percent (applying a safety ctor of 2) demonstrates the assumed accident analysis efficiencies of 70 percent for meth 1 iodide and 90 percent for elemental iodine. This conclusion is supported by a July 1,2000 letter from NCS Corporation that stated "Nuclear grade activated carbon, when sted in accordance with ASTM D3803-1989 (methyl iodide...)

to a penetration of 15%, i more conservative than testing the same carbon in accordance with ASTM D3803-1979 lemental iodine...) to a penetration of 5%....As a general rule, you may expect the radi.odine penetration through nuclear grade activated carbon to increase from 20 to 100 times when switching from elemental iodine to methyl iodide testing." Therefore, the efficie cies of the HEPA filters and charcoal adsorbers are demonstrated to be as specified, at flow rates, temperatures, velocities, and relative humidities which are less than the sign values of the system, the resulting doses will be less than or equal to the limits speci din 10 CPR 5,0.67 or Regulatory Guide 1.183 for r the accidents analyzed. The demonstra.on of bypass 1% and demonstration of 86 percent methyl iodide removal efficiency will a sure the required capability of the adsorbers is met or exceeded.

The surveillance frequency of the mechanical properties (i.e., flowrates, differential pressures) of the ventilation systems is based on operating experience, equipment reliability and plant risk and is controlled under the Surveillance Frequency Control Program.

4.13 RCSOPERATIONALLEAKAGE Applicability TS 4.13-1 11 05 09

, the following surveillances shall be performed at the frequencies specified in the Surveillance Frequency Control Program.

The following specifications are applicable to RCS operatio 1LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahre it).

Objective To verify that RCS operational LEAKAGE is maintained within the allowable li Specifications A.

Verify RCS operational LEAKAGE is within the limits specified in TS 3.1.C by performance of RCS water inventory balance 6f1:eeevery 24 ft6tlfS.l, 2 B.

Verify primary to secondary LEAKAGE is::; 150 gallons per day through anyone SG ofl:ee evefY 72 ft6tlfS, with the following exception. The primary to secondary LEAKAGE for the Unit 1 B steam generator will be verified to be ::; 20 gallons per day during Operating Cycle 23.1 If it is not practical to assign the LEAKAGE to an {

individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

Notes:

1.

Not required to be completed 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.

BASES SURVEILLANCE REQUIREMENTS (SR)

SR4.13.A Verifying RCS LEAKAGE to be within the Limiting Condition for Operation (LCO) limits ensures the integrity of the reactor coolant pressure boundary (RCPB) is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by

\\

performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions (stable pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The surveillance is modified by two notes.

Note 1 states that this SR is not required to be completed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable unit conditions are established.

Amendment Nos. 264 and 266

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.

6£ea:fiyleakage deteeti6n in the pIegention of accidents.

SR4.13.B TS 4.13-2 05-07 09 This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through anyone SG, with the following exception. The primary to secondary LEAKAGE for the Unit 1 B steam generator will be limited to 20 gallons per day during Operating Cycle 23.

Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.1.H, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 4. The operational LEAKAGE rate limit applies to LEAKAGE through anyone SG.

If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG; for Unit 1 that leakage should be assumed to be through the B steam generator for Operating Cycle 23. The surveillance is modified by a Note, which states that the Surveillance is 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. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

aeeicleHts. The pn to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical gr ling in accordance with the EPRI guidelines (Ref. 4).

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.

Amendment Nos. 264 and 250

TS 4.13-2a 07-22-09 SR 4.13.A and SR 4.13.B / Note 1 With respect to SR 4.13.A and SR 4.13.B, as the associated Note 1 modifies the required I

~on of the surveillance, it is construed to be part of the specified completion time. Should surveillance 1 e f 72 hstir interval be exceeded while steady state operation has not been established, Note 1 allows 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation to complete the surveillance.

The surveillance is still considered to be completed within the specified completion time.

Therefore, if the surveillance were not completed within the r (plus extension allowed by TS 4.0.2) interval, but steady state operation had not been e ablished, it would not constitute a failure of the SR. Once steady state operation is establishe 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months would be allowed for completing the surveillance. If the surveillance were not co leted within this 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval, there would a failure to complete a surveillance within the sp ified completion time, and the provisions of SR 4.0.3 would apply.

REFERENCES required surveillance interval 1.

UFSAR, Chapter 4, Surry Units 1 and 2.

2.

UFSAR, Chapter 14, Surry Units 1 and 2.

3.

NEI 97-06, "Steam Generator Program Guidelines."

4.

EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

Amendment Nos. Bases-

TS 4.16-1

..Ql 25-~

4.16 LEAKAGE lESTING OF MISCELLANEOUS RADIOACTIVE MATERIALS SOURCES Applicability Applies to miscellaneous radioactive materials sealed sources not subject to core flux and that are not stored and out of use.

Objective To maintain doses due to ingestion or inhalation within the limits of 10 CFR 20.

Specifications A.

Source Leakage Test Radioactive sources shall be leak tested for contamination. The leakage test shall be capable of detecting the presence of 0.005 microcurie of radioactive material on the test sample. If the test reveals the presence of 0.005 microcurie or more of removable contamination, it shall immediately be withdrawn from use, decontaminated, and repaired or be disposed of in accordance with Commission regulations.

Those quantities of byproduct material that exceed that quantities listed in 10 CFR 30.71 Schedule B are to be leak tested in accordance with the schedule shown in Surveillance Requirements. All other sources (including alpha emitters) containing greater than 0.1 microcurie are also to be leak tested in accordance with the Surveillance Requirements.

I B. Surveillance Requirements 1.

Test for leakage and/or contamination shall be performed by the licensee or by other persons specifically authorized by the Amendment Nos. 185 and 185

TS 4.16-2 01-25-94 Commission or an agreement State as follows:

at the frequency specified in the Surveillance Frequency Control Program adioactive materials in possession shall be maintained shall be leak tested prior to and following any repair or efore being subjected to core flux.

a.

Each sealed source, except startup sources subject to core flux, containing radioactive material other than Hydrogen 3 with a half-life greater than thirty days and in any form other than gas shall be tested for leakage and/or contamination intel vB:ls n6t t6 exeeea ShE ffl8RtRS.

the frequency specified in the Surveillance b.

The periodic leak test required does n Freauencv Control Proaram.

and not being used. The sources excepted from this test shall be tested for leakage prior to any use or transfer to another user unless they have been leak tested within six m6n:ths prior to the date of use or transfer. In the absence of a certific te from a transferor indicating that a test has been made within six fEI:e~17pr r to the transfer, sealed sources shall not be put into use until tested.

2.

A complete i current at all ti c.

Basis the frequency specified in the Surveillance Frequency Control Program.

specification assures that lea ge from radioactive materials sources does not exceed allowable limits. The limits for all other ources (including alpha emitters) are based upon 10 CFR 70.39(c) limits for plutonium.

Ingestion or inhalation of so rce material may give rise to total body or organ irradiation. This Amendment Nos. 185 liBa 185

in accordance with the frequency specified in the Surveillance Frequency Control Program.

TS 4.18-1,r-07-07-08 ROOM MCRJESGR 4.18 MAIN CONTROL ROOMIEMERGENCY EMERGENCY VENTILATION SYSTEM EVS A. Operate each MCRJESGR EVS train for 2 15 minut.~~~~~~~~

B. Perform required Control Room Air Filtration System Testing in accordance with TS 4.20.

C. Perform required MCRJESGR envelope unfiltered air inleakage testing in accordance with the MCRJESGR Envelope Habitability Program.

BASES SURVEILLANCE REQUIREMENTS (SR)

SR 4.18.A Standby systems should be checked periodically to ensure that they function properly. A8-tfte oaG@ @¥@ry FH:oatH pro¥idss aa adsEjl:1ate eHsek of tffis systsffl:. Systems without heate need only be operated for 2 15 minutes to demonstrate the function of the system. iile-:;+-I~4fE!lEtl:1'ei*~

bftSe6 Oft the I eliftbilit) of the efltlipmeftt ftft6 the t 9V 0 tfftift re6tlft6ftfte).

MCRJESGR EVS trains shall be initiated manually from the MCR.

SR4.18.B This SR verifies that the required Control Room Air Filtration Syste testing is performed in accordance with Specification 4.20. Specification 4.20 includes tes.ng the performance of the HEPA filter, charcoal adsorber efficiency, minimum flow rate, an he physical properties of the activated charcoal. Specific test frequencies and additional infor ation are discussed in detail in TS 4.20.

SR4.18.C This SR verifies the OPERABILITY of the MCRI GR envelope boundary by testing for unfiltered air inleakage past the MCR/ESGR env ope boundary and into the MCR/ESGR envelope. The details of the testing are specifie in the MCR/ESGR Envelope Habitability Program (TS 6.4.R).

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.

Amendment Nos. 260 aaE1268

TS 6.4-15 07-07-08 4.

Measurement, at designated locations, of the MCRlESGR envelope pressure relative to all external areas adjacent to the MCRlESGR envelope boundary during the pressurization mode of operation by one train of the MCR/ESGR EVS, operating at the flow rate required by TS 4.20, at a Frequency of 18 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the assessment of the MCRlESGR envelope boundary.

5.

The quantitative limits on unfiltered air inleakage into the MCRlESGR 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 3. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of MCR/ESGR envelope occupants to these hazards will be within the assumptions in the licensing basis.

6.

The provisions of SR 4.0.2 are applicable to the Frequencies for assessing MCRlESGR envelope habitability, determining MCRlESGR envelope unfiltered inleakage, and measuring MCR/ESGR envelope pressure and assessing the MCRlESGR envelope boundary as required by paragraphs 3 and 4, respectively.

6.4.S Surveillance Frequency Control Program (SFCP)

This program provides controls for Surveillance Frequencies. The program shall ensure that 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 NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies,"

Revision 1.

c. The provisions of Surveillance Requirements 4.0.2 and 4.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

Amendment Nos. 260 ftftel260

Serial No.1 0-183 Docket Nos. 50-280/281 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 4 TSTF-425 (NUREG-1431) VS. SURRY TS CROSS-REFERENCE VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY UNITS 1 AND 2

Serial No.10-183 Cross Reference NUREG-1431 to Surry TS Page 1 of 10 CROSS REFERENCE NUREG*1431 TSSURVEILLANCE REQUIREMENTS TO SURRY TS SURVEILLANCE REQUIREMENTS REMOVED Technical Specification Section Title/Surveillance Description*

TSTF 425 SPS Shutdown margin Verify SDM SR 3.1.1.1 Core Reactivity Verify Measured Core Reactivity within Predicted Value SR 3.1.2.1 TS 4.10.A Rod Position Verify Rod Position -Alignment SR3.1.4.1 Table 4.1-1, Item 9 Verify Rod Movement SR 3.1.4.2 Table 4.1-2A, Item 2 Verify Rod Drop Time Table 4.1-2A, Item 1 Shutdown Bank Verify Alignment SR 3.1.5.1 Table 4.1-1, Item 9 Control Bank Insertion limit Verify Limits SR 3.1.6.3 Verify Control Bank Rod Sequence and Overlap SR 3.1.6.4 Rod Position Indication Calibration of RPI Table 4.1-1, Item 9 Physics Test Exceptions RCS Loop Temperature SR 3.1.8.2 Verify Thermal Power SR 3.1.8.3 Verify SDM SR 3.1.8.5 Verify AFD 3.12.B.4.d.2 FQ(Z) Limits Verify Fa(Z) limits SR3.2.1.1 TS 3.12.B.2; TS 4.1O.B Verify F~ (Z) limits SR 3.2.1.2 TS4.10.B F~H Limits Verify F~H (Z) limits SR 3.2.2.2 AFD Limits Verify AFD Limit SR 3.2.3.1 TS 3.12.B.3 QPTR Verify QPTR by calculation SR 3.2.4.1 Verify QPTR wI incore detectors SR 3.2.4.2 RPS Instrumentation Channel Check SR 3.3.1.1 TS 4.1.AlTable 4.1-1 Check Column Perform Calorimetric - actual power adjust if > 3%

SR 3.3.1.2 TS 4.1.AlTable4.Fr, Item 1 Compare and Adjust NIS to Incore SR 3.3.1.3 TS 4.1.AlTable 4.1-1, Item 1 TADOT - Rx Trip Breakers SR 3.3.1.4 TS 4.1.AlTable4.1-1, Item 30 Actuation Logic Test SR 3.3.1.5 TS 4.1.AlTable 4.1-1,,

Item 26

Serial No.10-183 Cross Reference NUREG-1431 to Surry TS Paae 2 of 10 Technical SDecification Section Title/Surveillance Description*

TSTF 425 SPS Calibrate NIS to Incore SR 3.3.1.6 TS 4.1.NTable 4.1-1, Item1 COT 92 days SR 3.3.1.7 TS 4.1.NTable4.1-1, Item 3 COT - Source Range SR3.3.1.8 TS 4.1.NTable 4.1-1, Item 3 TADOT SR 3.3.1.9 TS 4.1.A!Table 4.1~1 Test Column Channel Calibration OT/OP AT SR 3.3.1.10 TS 4.1.NTable 4.1-1 Item 4 Channel Calibration SR 3.3.1.11 TS 4.1.A!Table 4.1-1, Item 1 Channel Calibration SR 3.3.1.12 TS 4.1.A!Table 4.1-1, Calibration Column COT SR 3.3.1.13 TS 4.1.A!Table 4.1-1, Test Column TADOT SR 3.3.1.14 TS 4.1.A!Table 4.1"1, Test Column Response Time SR 3.3.1.16 ESFAS Instrumentation Channel Check SR 3.3.2.1 TS 4.1.A!Table 4.1-1 Actuation Logic Test (92 days)

SR3.3.2.2 Actuation Logic Test (31 days)

SR 3.3.2.3 TS4.1.NTable 4.1-1 Item26 Master Relay Test SR 3.3.2.4 COT SR 3.3.2.5 TS 4.1.A!Table 4.1-1.

Slave Relay Test SR3.3.2.6 TS 4.11.C.5.a&b; Table 4.1-2A TADOT SR3.3.2.7 TS 4.1.A!Table 4.1-1 TADOT SR 3.3.2.8 TS 4.1.NTable 4.1-1 Channel Calibration SR3.3.2.9 TS 4.1.NTable 4.1-1 Time Response SR 3.3.2.10 PAM Instrumentation PAM Channel Check SR 3.3.3.1 TS 4.1.ClTable 4.1-2 PAM Channel Calibration SR 3.3.3.2 TS 4.1.ClTable 4.1-2 Remote Shutdown System Channel Check SR 3.3.4.1 TS 4.1.ClTable 4.1-2 Control and Transfer Switch Test SR 3.3.4.2 Channel Calibration SR 3.3.4.3 TS 4.1.ClTable 4.1-2 TADOT of Reactor Trip Breaker SR 3.3.4.4 LOPEDG StartInstrumentation Channel Check SR 3.3.5.1 TADOT SR 3.3.5.2 Table4.1-1 Item 33.a Channel Calibration SR 3.3.5.3 Table4.1-1 Item 33.b

Serial No.10-183 Cross Reference NUREG-1431 to Surry TS P

3 f10 aae a

Technical SDecification Section Title/Surveillance Description*

TSTF 425 SPS Containment Purge and Vent Isolation Channel Check SR 3.3.6.1 Actuation Logic Test SR 3.3.6.2 Master Relay Test SR 3.3.6.3 Actuation SR 3.3.6.4 Master Relay Test SR 3.3.6.5 COT SR 3.3.6.6 Slave Relay Test SR 3.3.6.7 TADOT SR 3.3.6.8 Channel Calibration SR 3.3.6.9 CREFAS Channel Check SR 3.3.7.1 COT SR 3.3.7.2 Actuation Logic Test SR 3.3.7.3 Table 4.1-2A Item 15 Master Relay Test SR3.3.7.4 Actuation Logic Test SR 3.3.7.5 Master Relay Test SR 3.3.7.6 Slave Relay Test SR 3.3.7.7 TADOT SR 3.3.7.8 Channel Calibration SR 3.3.7.9 FBACS Actuation Instrumentation Channel Check SR 3.3.8.1 Note 1 COT SR 3.3.8.2 Note 1 Actuation Logic Test SR 3.3.8.3 Note 1 TADOT SR 3.3.8.4 Note 1 Channel Calibration SR 3.3.8.5 Note 1 BOPS Channel Check SR 3.3.9.1 Note 1 COT SR 3.3.9.2 Note 1 Channel Calibration SR 3.3.9.3 Note 1 WasteGas Decay Tanks (Surry Specific)

Testand Calibrate theOxygen Mon!tor TS 4.1AlTable 4.1-1A, TS RCS Press Temp & Flow Limits Verify Pressurizer Pressure SR 3.4.1.1 TS 3.12.F.1.a Verify RCS Temperature SR 3.4.1.2 TS 3.12.F.1.a Verify RCS total Flow SR 3.4.1.3 TS 3.12.F.1.b Table 4.1-2A Item 22 Verify RCS Total Flow wi Heat Balance SR 3.4.1.4 RCS Minimum Temp for Criticality Verify each Loop SR 3.4.2.1 RCS Temperature, Pressure, Verify Limits SR 3.4.3.1

Serial No.10-183 CrossReference NUREG-1431 to SurryTS P

4 f1 aQe 0

0 Technical Specification Section Title/Surveillance Descrletlon" TSTF 425 SPS Loop Operetlon-Modes 1 and 2 Verify loop operating SR 3.4.4.1 Loop Operatlon-Mode 3 Verify loop operating SR 3.4.5.1 Verify Steam Generatorwater Levelz 17%

SR 3.4.5.2 Verify BreakerAlignment and Power Available SR 3.4.5.3 Loop Operatlon-Mode 4 Verify Loop Operation - Mode4 SR 3.4.6.1 Verify Steam Generatorwater Level~ 17%

SR 3.4.6.2 Verify BreakerAlignment and Power Available SR 3.4.6.3 Loop Operation-Mode 5 - Loops Filled Verify loop operating SR 3.4.7.1 Verify SteamGeneratorwater Level~ 17%

SR 3.4.7.2 Verify BreakerAlignment and Power Available RHR Pumps SR 3.4.7.3 Verify Loop Operation-Mode 5 - Loops Not Filled Verify RHROperating SR 3.4.8.1 Verify BreakerAlignment and Power Available RHR Pumps SR 3.4.8.2 Pressurizer VerifyWater Level SR 3.4.9.1 TS 4.1.B.2 Verify Heater Capacity of Required Groups SR 2.4.9.2 Verify Heaterbankscan be Powered for Emergency Power SR 3.4.9.4 Pressurizer PORVS Cycle each Block Valve SR 3.4.11.1 TS 4.1.B.1.c Cycle each PORV SR 3.4.11.2 TS 4.1.B.1.a Cycle each SOV Valve and Check Valve on the Air SR 3.4.11.3 TS 4.1.B.1.b Accumulators in PORVControl Systems Verify PORVs and Block Valves can be Powered from SR 3.4.11.4 Ernerqency PowerSources Verify PORVBackup Nitrogen SupplyPressure ts 4.1.B.1.d Functional Test and Calibration of PORV Backup Air Instrumentation andAlarm ts 4.1.B.1.e PORVOperational Relief Valve Control System Table 4.1-2A Item 18 LTOP Systems Verify only one LHSI pumpis capableof injecting into the RCS.

SR 3.4.12.1 Verify a maximum of one charging pump is capable of injecting SR 3.4.12.2 TS 3.1.G.1.b.1 into the RCS Verify each accumulator is isolated SR 3.4.12.3 TS 3.1.G.1.b.2 Verify each RHRSuction Valve is open for each Relief Valve SR 3.4.12.4 Verify required RCSvent [2.07]squareinchesopen SR 3.4.12.5 Verify PORVblockvalve is openfor each required PORV SR 3.4.12.6 TS 3.1.G.c.(5)

Verify Nitrogen Pressure Verify RHR Suction Isolation Valve is Locked Open for SR 3.4.12.7 Required RHR Suction Relief Valve.

Channel Calibration SR 3.4.12.9 Table 4.1-2A Items 16 &18

Serial No.10-183 CrossReference NUREG-1431 to SurryTS Paae 5 of 10 Technical Specification Section Title/Surveillance Descrlntlon" TSTF425 SPS VerifySetpoint for PORV Backup Air Supply Table 4.1-2A Item 17 Operational Leakage Verify RCS operational leakage SR3.4.13.1 TS 4.13.A Verify 5150 gpd/SG SR 3.4.13.2 TS 4.13.B RCS PIVs Verifyleakage from eachis50.5 gpm SR 3.4.14.1 Table 4.1-2A Item 19 RCS Leakage Detection Instrumentation Channel Check SR 3.4.15.1 COT SR 3.4.15.2 Channel Calibration SumpMonitor SR 3.4.15.3 Channel Calibration containment atmosphere radioactivity SR 3.4.15.4 monitor.

Channel Calibration containment air cooler.

SR 3.4.15.5 RCS Specific Activity Verify RCSgrossspecificactivity SR 3.4.16.1 Table 4.1-2B Item 1 VerifyreactorcoolantDose Equivalent 1-131 SR 3.4.16.2 Table4.1-2B Item1 Determine E Bar SR 3.4.16.3 Table4.1-2B Item 1 Tritium Activity Table4.1-28 Item 1 Chemistry Cl, F, andO2 Table4.1-2B Item 1 Boron Concentration Table4.1-2B Item 1 VerifyStackGas Iodineand Particulate Table4.1-2B Item 7 RCS Loop Isolation Valves Verifypowerremove from Isolation valve SR 3.4.17.2 RCS Loops Test Exceptions Verifypower< P-7 SR 3.4.19.1 Accumulators VerifyAccumulator isolation valveopen SR 3.5.1.1 Verifyborated WaterVolume SR 3.5.1.2 TS 4.11.B.1.a Verify N2 Pressure SR 3.5.1.3 TS 4.11.B.1.b Verify Boron Concentration SR 3.5.1.4 TS 4.11.B.2 Verify Power removed from isolation valve SR 3.5.1.5 ECCS - Operating VerifyValveLineup SR 3.5.2.1.1 Verify Manual Valve Position SR 3.5.2.1.2 Verify Piping Sufficiently Full SR 3.5.2.1.3 VerifyAutomatic ValvePosition SR 3.5.2.1.5 TS 4.11.5.a Verify Pump Start SR 3.5.2.1.6 TS 4.11.5.b VerifyThrottle ValvePosition SR3.5.2.1.7 Inspection SumpComponents SR 3.5.2.1.8 TS 4.11.5.c RWST VerifyWaterTemperature SR3.5.4.1 TS 4.11.A.1

Serial No.10-183 CrossReference NUREG-1431 to SurryTS P

f ace 6 a 10 Technical Specification Section Title/Surveillance Description*

TSTF425 SPS VerifyWater Volume SR 3.5.4.2 TS 4.11.A.2.a VerifyBoron Concentration SR3.5.4.3 TS 4.11.A.2.b VerifyChemistry CI and F Table4.1-2B Item 2 Verify BoricAcidTanksBoron Concentration Table4.1-2B Item 3 Seal Injection Flow Verifythrottle ValvePosition SR 3.5.5.1 BIT VerifyWaterTemperature SR 3.5.6.1 Note 1 VerifyWater Volume SR 3.5.6.2 Note 1 VerifyWater Boron Concentration SR 3.5.6.3 Note 1 Containment Air Locks Verify Interlock Operation SR 3.6.2.2 Containment Isolation Valves Verify Purge Valves Sealed Closed (outside containment)

SR 3.6.3.1 TS 4.1.F.1 and 2 Verify Purge Valves Closed (inside containment)

SR 3.6.3.2 TS 4.1.F.1 and2 VerifyValves Outside Containment in Correct Position SR 3.6.3.3 TS 4.1.G.

Verify Isolation Time of Valves SR 3.6.3.5 1ST Program CycleWeightLoaded Check Valves - 92 days SR 3.6.3.6 Perform LeakRate Test of Purge Valves SR 3.6.3.7 Table 4.1-2A Item 20 VerifyAutomatic Valves Actuate to Correct Position SR 3.6.3.8 Table4.1-2A Item 6 Cycle NonTestable Ouring Power WeightLoaded Check Valves SR 3.6.3.9 4.5.C Verify Purge Valves Blocked SR 3.6.3.10 Containment Pressure Verify Pressure SR 3.6.4.1 Containment AirTemperature VerifyAverage Air Temperature SR 3.6.5.1 SpraySystems VerifyValve Position SR3.6.60.1 VerifyValveActuation SR 3.6.60.3 Table 4.1-1 Item 17 Verify Pump Starton AutoSignal SR 3.6.60.4 Table 4.1-1 Item 17 Verify Nozzle are notObstructed SR 3.6.60.5 VerifyOperability of Weight-Loaded CheckValves TS 4.5.C Recirculation Spray VerifyCasing Cooling Temperature SR 3.6.6E.1 Note 1 Verifying Casing Cooling Volume SR 3.6.6E.2 Note1 VerifyCasing Cooling Boron Concentration SR 3.6.6E.3 Note 1 VerifyValve Position SR 3.6.6E 4 VerifyActuation of Pumps andValves SR 3.6.6E.6 Table 4.1-1 Item 16 Verify Nozzle are not Obstructed SR3.6.6E.7 Inspect SumpComponents TS 4.5.0 VerifyOperability of Weight-Loaded Check Valves TS 4.5.C

Serial NO.1 0-183 Cross Reference NUREG-1431 to SurryTS Paae 7 of 10 Technical Specification Section Title/Surveillance Description*

TSTF425 SPS Spray Additive System VerifyValveposition SR 3.6.7.1 VerifyTankVolume SR 3.6.7.2 VerifyTankSolution Concentration SR 3.6.7.3 Table4.1-2B Item 4 Actuate Each FlowPathValve SR 3.6.7.4 Table4.1-2AItem 3 SR3.6.7.5 Iodine Cleanup System Operate trainwith heaters SR3.6.11.1 Note 1 VerifytrainActuation SR 3.6.11.3 Note 1 Verify FilterBypass Operation SR 3.6.11.4 Note1 Main Steam Isolation Valves Actuate Valves SR 3.7.2.2 Table 4.1-2A Item 13 TS 4.7.A.1 MFIVs and MFijVs Actuate Valves SR 3.7.3.2 Atmospheric Dump Valves Cycle Dump Valves SR 3.7.4.1 Cycle BlockValves SR 3.7.4.2 AFW VerifyValve Position SR 3.7.5.1 TS 4.8.A.1.a VerifyAutoValveActuation SR 3.7.5.3 TS 4.8.A.6.a Verify Pump Auto Actuation SR 3.7.5.4 TS 4.8.A.6.b Emergency Condensate Storage VerifyVolume SR 3.7.6.1 Component Cooling VerifyValvePosition SR 3.7.7.1 VerifyValveActuation SR 3.7.7.2 Note 1 Verify Pump Actuation SR 3.7.7.3 Note1 Service Water VerifyValvePosition SR 3.7.8.1 VerifyValveActuation SR 3.7.8.2 Table 4.1-2A Items 8 and 14.a and b Verify PumpActuation SR 3.7.8.3 Note 1 Ultimate HeatSink VerifyWater Level SR 3.7.9.1 TS 4.1.A!Table 4.1-1 Item 40 VerifyWaterTemperature SR 3.7.9.2 Operate Cooling Tower SR 3.7.9.3 Note 1 Verify FanActuation SR 3.7.9.4 Note 1 CR Emergency Ventilation Operate Heaters SR 3.7.10.1 4.18.A VerifyTrain Actuation SR 3.7.10.3 TS 4.1-2AItem 15 Verify Envelope Pressurization SR 3.7.10.4

Serial No.10-183 Cross Reference NUREG-1431 to SurryTS P

8 f10 age 0

Technical SDecification Section Title/Surveillance Description*

TSTF425 SPS CR Air Condition System VerifyTrain Capacity SR3.7.11.1 ECCSPREACS Operate Heaters SR 3.7.12.1 TS 4.12.A.1 VerifyAutomatic Train Actuation SR 3.12.3 TS 4.12.A.2 Verify Envelope Negative Pressure SR 3.12.4 VerifyBypass Damper Closure SR 3.12.5 Fuel Building Air Cleanup Operate Heaters SR3.7.13.1 VerifyAutomatic Train Actuation SR 3.7.13.3 Verify Envelope Negative Pressure SR 3.7.13.4 VerifyBypass Damper Closure SR 3.7.13.5 Penetration Room Air Cleanup System -

Operate Heaters SR 3.7.14.1 Note1 VerifyAutomatic Train Actuation SR 3.7.14.3 Note 1 Verify Envelope Pressurization SR 3.7.14.4 Note 1 Verify Bypass Damper Closure SR 3.7.14.5 Note 1 Fuel Storage Pool Water Level VerifyWater Level SR 3.7.15.1 Fuel Storage Pool Boron Verify Boron Concentration SR 3.7.16.1 Table4.1-2B Item 5 Secondary Specific Activity VerifySecondary Activity SR 3.7.18.1 Table4.1-2B Item 6 Radioactive Gas StorageMonitoring System (Surry Specific)

Verifyradioactive materialin eachgas storagetank TS4.9.B AC Sources -Operating Verify Breaker Alignment Offsite Circuits SR 3.8.1.1 Verify EDG Starts-Achieves Voltage & Frequency SR 3.8.1.2 TS 4.6.A.1.a Synchronize and Load for> 60 minutes SR 3.8.1.3 TS 4.6.A.1.a Verify DayTank Level SR 3.8.1.4 Remove Accumulate Waterfor DayTank SR3.8.1.5 VerifyOperation of TransferPump SR 3.8.1.6 TS 4.6.A.1.c Verify EDG Starts-Achieves Voltage & Frequency in 10seconds SR 3.8.1.7 TS 4.6.A.1.b VerifyManual Transfer of AC power Sources - OffsiteSources SR 3.8.1.8 TS4.6.A.1.a Verify Largest Load Rejection SR 3.8.1.9 Verify EDG DoesNot Tripwith Load Rejection SR 3.8.1.10 TS 4.6.A.1.b Verify De-energize, Load Shed and Reenergize Emergency Bus SR 3.8.1.11 TS 4.6.A.1.b Verify EDG Starton ESFSignal SR 3.8.1.12 TS 4.6.A.1.b Verify EDG Noncritical Trips SR 3.8.1.13 TS 4.6.A.1.b Run EDG for 24 Hours SR 3.8.1.14 Verify EDG Starts-Achieves Voltage & Frequency SR 3.8.1.15

Serial NO.1 0-183 Cross Reference NUREG-1431 to SurryTS P

9 f1 age 0

0 Technical Specification Section Title/Surveillance Description" TSTF 425 SPS Verify EDG Synchronizes with offsitepower andtransfers load SR 3.8.1.16 TS 4.6.A.1.a VerifyTest Modeis Overrode on ESF Signal SR 3.8.1.17 VerifyLoadSequencers arewith Design Tolerance SR 3.8.1.18 TS 4.6.A.1.b Verify EDG Starton Lossof Offsite Power SR 3.8.1.19 TS 4.6.A.1.b Verifywhen started Simultaneously each EDGs reach rated SR 3.8.1.20 Voltage and Frequency EDG inspection TS 4.6.A.1.d Diesel FO and Starting Air Verify FOStorage Tank Volume SR 3.8.3.1 Table 4.1-2A, Item 11 Verify LubeOil Inventory SR 3.8.3.2 Verify EDG StartAir Receive Pressure SR 3.8.3.4 Checkand Remove Accumulate Waterfrom FOTanks SR 3.8.3.5 Verify FuelOil Supply Table 4.1-2A Item 11 Verify FuelOil SupplyBelowGround Tank during Cleaning and TS 3.16.BA.b Inspection Verify FuelOil SupplyAboveGround Tanks during Cleaning and TS 3.16.BA.c Inspection DC Sources Operating -

Station and EDG Batteries VerifyBattery Terminal Voltage SR 3.8.4.1 VerifyStation Battery Chargers Capable of Supplying [x]Amp for SR 3.8.4.2

[y]Hours Perform Battery Service Test SR 3.8.4.3 Cleanand CoatStation and EDG Battery Terminals TS 4.6.C.1.f TS 4.6.D.1.e Perform Simulated Load Test TS 4.6.C.1.e TS 4.6.D.1.d Compare Battery Voltage and Current w/out Battery charger connected TS 4.6.C.1.d TS 4.6.D.1.c Battery Parameters Station and EDG Batteries Verifyeach Battery FloatCurrent is.$. [2] amps.

SR 3.8.6.1 Verifyeach Battery PilotCellVoltage is ~[2.07] V SR3.8.6.2 TS 4.6.C.1.b TS 4.6.D.1.b Verifyeach Battery Cell Electrolyte Level is ~ to Minimum Design SR 3:8.6.3 TS 4.6.C.1.c Limits.

TS 4.6.D.1.c Verifyeach Battery PilotCellTemperature ~ to Minimum Design SR 3.8.6.4 TS 4.6.C.1.a andc Limits.

TS 4.6.D.1.a andc Verify Each Battery Connected CellVoltage is~[2.07] V.

SR 3.8.6.5 TS 4.6.C.1.b TS4.6.D.1.b VerifyStation and EDG Battery Capacity - >80%after SR 3.8.6.6 Performance Test Inverters - Operating Verify Correct Inverter Voltage &Alignment toRequired AC Vital Buses.

SR 3.8.7.1

SerialNO.10-183 Cross Reference NUREG-1431 to SurryTS P

f age 100 10 Technical Specification Section Title/Surveillance Description*

TSTF 425 SPS Inverters* Shutdown VerifyCorrect Inverter Voltage & Alignment to Required AC Vital SR 3.8.8.1 Buses.

Distribution System* Operating VerifyCorrect Breaker Alignments andVoltage to AC, DC, and SR 3.8.9.1 AC Vital Bus Electrical Power Distribution Subsystems.

Distribution System* Shutdown VerifyCorrect Breaker Alignments andVoltage to AC, DC, and SR 3.8.10.1 AC Vital Bus Electrical Power Distribution Subsystems.

Boron Concentration VerifyBoronConcentration is Within the LimitSpecified in COLR SR 3.9.1.1 Spent Fuel PoolBoronConcentration Table 4.1-2B, Item5 Primary Grade Water Source Isolation Valves Verify Each Valvethat Isolates Unborated WaterSources is SR 3.9.2.1 Secured in the Closed Position Nuclear Instrumentation PerlormChannelCheck SR 3.9.3.1 Perlorm Channel Calibration SR 3.9.3.2 Containment Penetrations Verifyeach Required Containment Penetration is in the Required SR 3.9.4.1 Status.

Verify Each Required Containment Purge and Exhaust Valve Actuates to the Isolation Position on an Actuated or Simulated SR 3.9.4.2 Actuation Sianal.

RHR and Coolant Olrculatlon-High Water Level VerifyOne Loop is in Operation andCirculating Reactor Coolant SR 3.9.5.1 at a FlowRate of > [2800] gpm.

RHR and Coolant Circulation* Low Water Level VerifyOne Loopis in Operation andCirculating Reactor Coolant SR 3.9.6.1 at a flow rateof > [2800] gpm.

VerifyCorrect Breaker Alignment and Indicated Power Available SR 3.9.6.2 to the Reauired RHR Pump that is Notin Operation.

Refueling Cavity Water Level Verify Refueling Cavity Water Level is ~23 ft Above TheTop of SR 3.9.7.1 Reactor Vessel Flange.

Miscellaneous Radioactive Material Sources (Surry Specific)

Leak Checksourceswith> 30 day Half-Life TS 4. 16.a Leak ChecksourcesexemptfromtheSurveillance 4. 16.a TS 4. 16.b Note 1 -

ThIS system or function IS notIncluded Inthe SurrydeSign or TS.

Serial NO.1 0-183 Docket Nos. 50-280/281 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 5 PROPOSED NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY UNITS 1 AND 2

Serial No.1 0-183 Docket No. 50-280/281 Significant Hazards Consideration Page 1 of 2 PROPOSED NO SIGNIFICANT HAZARDS CONSIDERATION Description of Amendment Request:

This amendment request involves the adoption of approved changes to the standard technical specifications (STS) for Westinghouse Pressurized Water Reactors (NUREG-1431), to allow relocation of specific TS surveillance frequencies to a Iicensee-controlled program. The proposed changes are described in Technical Specification Task Force (TSTF)

Traveler, TSTF-425, Revision 3

(ADAMS Accession No.

ML090850642) related to the Relocation of Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b and are described in the Notice of Availability published in the Federal Register on July 6, 2009 (74 FR 31996).

The proposed changes are consistent with NRC-approved Industry/TSTF Traveler, TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative 5b." The proposed changes relocate surveillance frequencies to a licensee-controlled program, the Surveillance Frequency Control Program (SFCP). The changes are applicable to licensees using probabilistic risk guidelines contained in NRC-approved NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," (ADAMS Accession No.

071360456). In addition, administrative/editorial deviations of the TSTF-425 inserts and the existing TS wording are being proposed to fit the custom Technical Specification format.

Basis for proposed no significant hazards consideration: As required by 10 CFR 50.91 (a), the Dominion analysis of the issue of no significant hazards consideration is presented below:

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

Response: No.

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

Surveillance frequencies are not an initiator to any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased.

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

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

Serial No.10-183 Docket No. 50-280/281 Significant Hazards Consideration Page 2 of2

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

Response: No.

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

The changes do not alter assumptions made in the safety analysis. The proposed changes are consistent with the safety analysis assumptions and current plant operating practice.

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

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

Response: No.

The design, operation, testing methods, and acceptance criteria for systems, structures, and components (SSCs), specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TS), since these are not affected by changes to the surveillance frequencies. Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. To evaluate a change in the relocated surveillance frequency, Dominion will perform a probabilistic risk evaluation using the guidance contained in NRC approved NEI 04-10, Rev. 1 in accordance with the TS SFCP. NEI 04-10, Rev. 1, methodology provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide 1.177.

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

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

ML100900391

Contents

Text

1.0 DESCRIPTION

2.0 ASSESSMENT

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

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ML100900391

Text

1.0 DESCRIPTION

2.0 ASSESSMENT

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

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