Text

Issuance of Amendment Extended Diesel Generator Completion Times
	ML053490174
Person / Time
Site:	Wolf Creek
Issue date:	04/26/2006
From:	Donohew J; Plant Licensing Branch III-2
To:	Muench R; Wolf Creek
	Donohew J N, NRR/DLPM,415-1307
Shared Package
ML061170141	List: ML053490174; ML061170237;
References
	TAC MC1257
	Download: ML053490174 (34)
	v • d • e

April 26, 2006 Mr. Rick A. Muench President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation Post Office Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK GENERATING STATION - ISSUANCE OF AMENDMENT RE:

EXTENDED DIESEL GENERATOR COMPLETION TIMES (TAC NO. MC1257)

Dear Mr. Muench:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No.163 to Facility Operating License No. NPF-42 for the Wolf Creek Generating Station. The amendment consists of changes to the license, including the Technical Specifications (TSs), in response to your application dated October 30, 2003 (WO 03-0057), as supplemented by letters dated August 31 (ET 05-0016) and November 18 (ET 05-0025), 2005, and March 6 and April 14, 2006 (WO 06-0014 and WO 06-0018, respectively).

The amendment increases completion times (CTs) and adds requirements on the diesel generators at the Sharpe Station in TS 3.8.1, "AC Sources - Operating." The proposed changes to CTs in TS 3.8.9, "Distribution Systems - Operating," were withdrawn in the supplemental letter dated March 6, 2006. The amendment also revises a page in the license and adds three license conditions to Appendix D, "Additional Conditions," of the operating license.

A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

/RA/

Jack Donohew, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-482

Enclosures:

1. Amendment No. 163 to NPF-42

2. Safety Evaluation cc w/encls: See next page

April 26, 2006 Mr. Rick A. Muench President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation Post Office Box 411 Burlington, KS 66839

SUBJECT:

WOLF CREEK GENERATING STATION - ISSUANCE OF AMENDMENT RE:

EXTENDED DIESEL GENERATOR COMPLETION TIMES (TAC NO. MC1257)

Dear Mr. Muench:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 163 to Facility Operating License No. NPF-42 for the Wolf Creek Generating Station. The amendment consists of changes to the license, including the Technical Specifications (TSs), in response to your application dated October 30, 2003 (WO 03-0057), as supplemented by letters dated August 31 (ET 05-0016) and November 18 (ET 05-0025), 2005, and March 6 and April 14, 2006 (WO 06-0014 and WO 06-0018, respectively).

The amendment increases completion times (CTs) and adds requirements on the diesel generators at the Sharpe Station in TS 3.8.1, "AC Sources - Operating." The proposed changes to CTs in TS 3.8.9, "Distribution Systems - Operating," were withdrawn in the supplemental letter dated March 6, 2006. The amendment also revises a page in the license and adds three license conditions to Appendix D, "Additional Conditions," of the operating license.

A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

/RA/

Jack Donohew, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-482 DISTRIBUTION PUBLIC GHill (2)

Enclosures:

1. Amendment No.163 to NPF-42 LPLIV Reading RidsNrrDpr

2. Safety Evaluation RidsNrrDorl (CHaney/CHolden)

RidsNrrDorlLplg (DTerao) cc w/encls: See next page RidsNrrPMJDonohew RidsNrrDirsItsb (TBoyce)

RidsNrrLALFeizollahi EBrown RidsOgcRp MRubin (TS) ML061170237 RidsAcrsAcnwMailCenter TKoshy (AMD) ML061170141 RidsRegion4MailCenter (BJones) SDinsmore ACCESSION NO.: ML053490174 OFFICE LPL4/PM LPL4/LA EEEB/BC(A) DRA/APLA/BC OGC NRR/LPL4/BC NAME JDonohew LFeizollahi EBrown MRubin SUttal (NLO) DTerao DATE 4/13/06 4/26/06 03/15/2006 04/12/2006 4/25/06 4/26/06 DOCUMENT NAME: E:\Filenet\ML053490174.wpd OFFICIAL RECORD COPY

WOLF CREEK NUCLEAR OPERATING CORPORATION WOLF CREEK GENERATING STATION DOCKET NO. 50-482 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 163 License No. NPF-42

1. The Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment to the Wolf Creek Generating Station (the facility)

Facility Operating License No. NPF-42 filed by the Wolf Creek Nuclear Operating Corporation (the Corporation), dated October 30, 2003, as supplemented by letters dated August 31 and November 18, 2005, and March 6 and April 14, 2006, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and Paragraph 2.C.(2) of Facility Operating License No. NPF-42 is hereby amended to read as follows:

2. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 163, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated in the license. The Corporation shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

2.15 Additional Conditions The Additional Conditions contained in Appendix D, as revised through Amendment No.

163 , which are attached hereto, are hereby incorporated in the license. Wolf Creek Nuclear Operating Corporation shall operate the facility in accordance with the Additional Conditions.

3. The license amendment is effective as of its date of issuance and shall be implemented within 90 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

David Terao, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: April 26, 2006

ATTACHMENT TO LICENSE AMENDMENT NO. 163 FACILITY OPERATING LICENSE NO. NPF-42 DOCKET NO. 50-482 Replace the following pages of the license with the attached pages. The revised pages are to the license and to Appendix A, Technical Specifications, and Appendix D, Additional Conditions, of the license, and are identified by amendment number and contain marginal lines indicating the areas of change. The corresponding overleaf pages are provided to maintain document completeness.

REMOVE INSERT Page 5 of license Page 5 of license Page 3 of Appendix D Page 3 of Appendix D Pages of Appendix A Pages of Appendix A iii iii 3.8-2 3.8-2 3.8-3 through 3.8-39 3.8-3 through 3.8-39

3.8-40

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 163 TO FACILITY OPERATING LICENSE NO. NPF-42 WOLF CREEK NUCLEAR OPERATING CORPORATION WOLF CREEK GENERATING STATION DOCKET NO. 50-482

1.0 INTRODUCTION

By application dated October 30, 2003, as supplemented by letters dated August 31 and November 18, 2005, and March 6 and April 14, 2006 (Agencywide Documents Access Management System Accession No. ML033110564, ML052500517, ML053410163, ML060740425, and ML061100450, respectively), Wolf Creek Nuclear Operating Corporation (the licensee) requested changes to the Technical Specifications (TSs, Appendix A to Facility Operating License No. NPF-42) for the Wolf Creek Generating Station (WCGS).

The proposed amendment would increase the completion times (CTs) for TS 3.8.1, "AC Sources -

Operating," and add requirements on the diesel generators (DGs) at the Sharpe Station when a diesel generator is in an extended CT greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for an onsite inoperable DG. The DGs in TS 3.8.1 are the Class 1E alternating current (AC) electric power DGs for onsite emergency power, but the "alternate DGs," or gensets, at the Sharpe Station are an alternate AC power available to WCGS when the plant is in an extended DG CT, but are not Class 1E AC power sources.

The proposed changes to TS 3.8.9, "Distribution Systems - Operating," in the licensee's application were withdrawn by the licensee in the supplemental letter dated March 6, 2006.

The supplemental letters dated August 31 and November 18, 2005, and March 6 and April 14, 2006, provided (1) responses to requests for additional information (RAIs) on the proposed amendment from the Nuclear Regulatory Commission (NRC) staff and (2) additional requirements to TS 3.8.1 to verify the Sharpe Station gensets are available and to restore the DG to operable status if these gensets are not available, respectively. The supplemental letters dated August 31 and November 18, 2005, provided additional information that clarified the application, did not expand the scope of the application as originally noticed and did not change the NRC staffs original proposed no significant hazards consideration determination published in the Federal Register on January 6, 2004 (69 FR 700).

In its application, the licensee provided the following attachments to its application: (1) the evaluation of the proposed amendment in Attachment I, (2) responses to NRC questions on Westinghouse Topical Report WCAP-15622, "Risk-Informed Evaluation of Extensions to AC Electrical Power System Completion Times," in Attachment II, (3) the marked-up Technical Specifications in Attachment III, (4) the revised Technical Specifications in Attachment IV, (5) the TS Bases changes (for information only) in Attachment V, and (6) the list of regulatory commitments in Attachment VI.

2.0 REGULATORY EVALUATION

For the TSs, Section 50.36 of Title 10 of the Code of Federal Regulations (10 CFR 50.36),

"Technical specifications," the NRC established its regulatory requirements related to the content of TSs. Pursuant to 10 CFR 50.36, TSs include items in the following five specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation (LCOs); (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls. The rule does not specify the particular requirements to be included in a plants TSs. As stated in 10 CFR 50.36(c)(2)(i), the "Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a LCO is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications ..."

The remedial actions in the TSs are specified in terms of conditions, required actions, and CTs to complete the required actions. When an LCO is not being met, the CTs specified in the TSs are the amount of time allowed for completing the specified LCO required actions. The conditions and required actions specified in the TSs must be acceptable remedial actions for the LCO not being met, and the CTs must be reasonable for completing the required actions.

General Design Criterion (GDC) 17, "Electric power systems," of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR 50 requires, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of structures, systems, and components (SSCs) that are important to safety. The onsite system is required to have sufficient independence, redundancy, and testability to perform its safety function, assuming a single failure.

The offsite power system is required to be supplied by two physically independent circuits that are designed and located so as to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. In addition, this criterion requires provisions to minimize the probability of losing electric power from the remaining electric power supplies as a result of a loss of power from the unit, the offsite transmission network, or the onsite power supplies.

GDC 18, "Inspection and testing of electric power systems," requires that electric power systems that are important to safety be designed to permit appropriate periodic inspection and testing.

"Loss of all alternating current power," 10 CFR 50.63, requires that all nuclear power plants must have the capability to withstand a loss of all AC power for an established period of time. This is further addressed by Regulatory Guide (RG) 1.155, "Station Blackout," which provides regulatory guidance acceptable to the NRC staff for alternate AC (AAC) power sources.

"Requirements for monitoring the effectiveness of maintenance at nuclear power plants," 10 CFR 50.65, requires that preventive maintenance activities must not reduce the overall availability of the SSCs. RG 1.93, "Availability of Electric Power Sources," provides guidance with respect to

operating restrictions (i.e., CTs) if the number of available AC power sources is less than that required by the TS LCO. In particular, this guidance prescribes a maximum CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for an inoperable AC power source. In addition, 10 CFR 50.65(a)(4) requires the assessment and management of the increase in risk that may result from the proposed planned maintenance activities.

General guidance for evaluating the technical basis for proposed risk-informed changes is provided in Chapter 19.0, "Use of Probabilistic Risk Assessment in Plant-Specific, Risk-Informed Decisionmaking: General Guidance," of the NRC Standard Review Plan (SRP),

NUREG-0800. More specific guidance related to risk-informed TS changes is provided in SRP Section 16.1, "Risk-Informed Decisionmaking: Technical Specifications," which includes CT changes as part of risk-informed decisionmaking. Chapter 19.0 of the SRP states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:

The proposed change meets the current regulations unless it is explicitly related to a requested exemption or rule change.

The proposed change is consistent with the defense-in-depth philosophy.

The proposed change maintains sufficient safety margins.

When proposed changes result in an increase in core damage frequency (CDF) or risk, the increase(s) should be small and consistent with the intent of the Commissions Safety Goal Policy Statement.

The impact of the proposed change should be monitored using performance measurement strategies.

RG 1.174, "An Approach for Using Probabilistic Risk Assessment [PRA] in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated November 2002, describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed licensing basis changes by considering engineering issues and applying risk insights.

RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998, identifies an acceptable risk-informed approach including additional guidance specifically geared toward the assessment of proposed TS CT changes.

Specifically, RG 1.177 identifies a three-tiered approach for the evaluation of the risk associated with a proposed CT TS change as identified below.

Tier 1 is an evaluation of the plant-specific plant operational risk associated with the proposed TS change, as shown by the change in core damage frequency (CDF) and change in large early release frequency (LERF). The change in risk is compared to the acceptance guidelines of RG 1.174. Tier 1 also evaluates the plant risk increase during the time equipment is removed from service as measured by the incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP). The incremental risk is compared to the acceptance guidelines of RG 1.177. Tier 1 also addresses PRA quality, including the technical adequacy of the licensees plant-specific PRA for the subject application.

Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed license amendment, is taken out of service simultaneously, or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The purpose of this evaluation is to ensure that there are appropriate restrictions in place such that risk-significant plant equipment outage configurations will not occur when equipment associated with the proposed CT is implemented.

Tier 3 addresses the licensees overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and appropriate compensatory measures to avoid such configurations are taken that may not have been considered when the Tier 2 guidance was developed. Compared with Tier 2, Tier 3 provides additional coverage to ensure risk-significant plant equipment outage configurations are identified in a timely manner and that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule (10 CFR 50.65(a)(4)), which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance, testing, and corrective and preventive maintenance, subject to the guidance provided in RG 1.177, Section 2.3.7.1, and the adequacy of the licensees program and PRA model for this application. The CRMP is to ensure that equipment removed from service prior to or during the proposed extended CT will be appropriately assessed from a risk perspective.

More specific methods and guidelines acceptable to the NRC staff are also outlined in RG 1.177 for assessing risk-informed TS changes. Specifically, RG 1.177 provides recommendations for utilizing risk information to evaluate changes to TS CTs and surveillance test intervals with respect to the impact of the proposed change on the risk associated with plant operation. RG 1.177 also describes acceptable implementation strategies and performance monitoring plans to help ensure that the assumptions and analysis used to support the proposed TS changes will remain valid.

3.0 TECHNICAL EVALUATION

3.1 Proposed Changes to the TSs In its application and the supplemental letter dated November 18, 2005, the licensee proposed the following changes to TSs 3.8.1:

2. Add the note to the CT in TS 3.8.1, for Required Action A.3, for an inoperable offsite AC source, to restore the offsite circuit to operable status, to state that "A Completion Time of 10 days from discovery of failure to meet the LCO may be used with the 7 day Completion Time of Required Action B.4 for an inoperable DG."

3. As an alternative to the current requirements in current Required Action B.4 (changed to B.4.1) of restoring the inoperable DG to operable status, add the required actions and CTs to periodically (once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ) verify the required number of gensets at the Sharpe Station are available (new Required Action B.4.2.1) and restore the inoperable DG to operable status within 7 days and 10 days from discovery of failure to meet LCO 3.8.1 (new Required Action B.4.2.2).

4. Add the note in TS 3.8.1, for new Required Action B.4.1, for an inoperable DG, to restore the DG to operable status, to state that "Required Actions B.4.2.1 and B.4.2.2 are only applicable for planned maintenance and may be used once per [operating] cycle per DG."

5. Add the new Condition C to TS 3.8.1 for not being able to verify the required gensets at the Sharpe Station are available. The proposed Required Action C.1 and CT for this condition are to restore the inoperable DG to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The current Conditions D through H, and associated required actions, would be administratively re-numbered, with no other changes to the conditions, required actions, or CTs, to new Conditions E through I, because of the addition of the new Condition C.

6. For existing Condition G, the condition is (1) re-numbered to Condition H because of the new Condition C being added and (2) revised. The revision to this condition revises the existing list of conditions and adds an additional requirement that for "Required Actions B.1, B.2, B.3.1, B.3.2, B.4.1, and B.4.2.2 and associated Completion Time not met" the plant shall be shut down.

The licensee is not proposing any changes to the CTs in TS 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation."

3.2 Description of Class 1E Power System The licensee described the Class 1E power system at WCGS in its application and in responses to RAIs 28 through 30 in Attachment I to its supplemental letter dated August 31, 2005. The licensee stated that the onsite power system is provided with preferred power from an offsite power source in accordance with GDC 17 (electric power systems) and 18 (inspection and testing of electric power systems) in 10 CFR Part 50, Appendix A, and RG 1.32, "Criteria for Power Systems for Nuclear Power Plants," dated February 1977. Offsite power is supplied to the plant switchyard from the transmission network by three transmission lines. With respect to the safety-related Class 1E power supply configuration, one preferred source from the switchyard provides to a multi-winding startup transformer, one winding of which provides power to a 13.8/4.16-kV engineered safety features (ESF) transformer. The second preferred, offsite AC power source supplies power from the switchyard to the second 13.8/4.16-kV ESF transformer. Each ESF transformer provides AC power to an associated safety-related Class 1E 4.16-kV bus. For each safety-related bus normally fed by its associated ESF transformer, there exists the capability for each bus to be supplied AC power by the other preferred source connection. Each offsite AC power source can be manually aligned to provide power to the opposite or both 4.16-kV buses, if this is required.

In the event of a loss-of-coolant accident (LOCA) and/or loss of offsite power (LOOP), the starting, or shedding and restarting, of Class 1E electrical loads is controlled by the load shedder and emergency load sequencers (LSELSs) for which there is one for each Class 1E 4.16-kV bus. In the event of a LOCA with preferred offsite power available to the 4.16-kV buses, the Class 1E loads are started in programmed time increments by the LSELS load sequencers with the DG(s) started but not connected to the bus. In the event of LOOP, the LSELS will automatically shed selected loads from the 4.16-kV bus, start the associated DG by the DG control circuitry, and start and load the required Class 1E loads in programmed time increments.

The licensee described the 10 engine-generator (gensets) available at the Sharpe Station, which is located two miles north of the WCGS site near an existing 69-kV substation. The gensets are two-megawatt Caterpillar 3516B engine-generator sets. Power from these gensets would enter the WCGS switchyard by the Phillips 69-kV line. The licensee stated that, because this station is so near the site, it can provide emergency backup AC power for WCGS, specifically to improve availability and reliability of sufficient AC power for planned or postulated WCGS plant conditions, such as planned onsite DG maintenance, loss of one or both DGs, grid perturbations. The licensee provided a comparison of the Sharpe Station gensets capabilities to an AAC power source as defined in RG 1.155, which is addressed in Section 3.4 of this safety evaluation (SE).

3.3 Evaluation of Proposed Extended DG CTs 3.3.1 Risk-Informed Review In accordance with the SRP of NUREG-0800, Chapter 19 and Section 16.1, the NRC staff reviewed the submittal using the three-tiered approach and five key principles of risk-informed decisionmaking presented in RG 1.177. The traditional engineering evaluation, which includes the compliance with current regulations, defense-in-depth, and evaluation of safety margins, is not addressed in the risk-informed review. These are considered in the deterministic review addressed in Section 3.3.2 of this SE.

The risk-informed review scope and findings are limited to the evaluation of the risk impacts of the proposed change to the TSs. The key information used in the NRC staffs risk evaluation is contained in the licensee's submittals which address the licensee's PRA model, and the licensees individual plant examination (IPE) and individual plant examination of external events (IPEEE) for WCGS.

The licensee stated that its methodology to justify extending the CT for an inoperable DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 7 days is consistent with the NRC approach for using probabilistic risk assessment (PRA) in risk-informed decisions on plant-specific changes to the current TSs, and plant licensing basis.

The risk evaluation considered the three-tiered approach presented RG 1.177:

1. Tier 1, PRA Capability and Insights

2. Tier 2, Avoidance of Risk-Significant Plant Configurations

3. Tier 3, Risk-Informed Plant Configuration Control and Management The criteria for Tier 1, Tier 2, and Tier 3 are addressed in Section 2.0 of this SE in the discussion on RG 1.177.

The Tier 1 review assessed the impact of the proposed extended CT on CDF, ICCDP, large early release frequency (LERF), and ICLERP. The Tier 2 review considered potential risk-significant plant operating configurations during the extended CT. The Tier 3 review addresses the plant-specific CRMP, including the risk-informed assessment for outages and what SSCs are controlled by the program. It is implemented consistent with the 10 CFR 50.65 Maintenance Rule program.

The licensee explained that RGs 1.174 and 1.177 provide risk guidelines for changes in CDF and ICCDP, and the change in risk for the extended DG CT was compared to these criteria. In referring to RG 1.174, the licensee stated that RG 1.174 is pertinent to proposed TS changes and

identifies that a "very small" increase in CDF (i.e., less than 1.0E-06) should be considered by the NRC. The licensee provided a table, on page 10 of 23 in Attachment I to its application, which listed the risk guidelines given in RGs 1.174 and 1.177 for plant-specific changes to the TSs, and/or plant licensing basis. Besides the critieria for the change in CDF, the CDF for the base case (in this case the existing DG CT) should be less than 1E-04/year.

The licensee stated that its risk methodology used in this application is in accordance with the risk guidelines in RGs 1.174 and 1.177. Therefore, based on RGs 1.174 and 1.177, the licensee concluded that an increase in CDF of 1.0E-06 is the threshold risk guidelines for the proposed extension to the DG CT in TS 3.8.1.

3.3.1.1 Tier 1 Considerations 3.3.1.1.1 PRA Capability for WCGS A table of the key milestones in the development of the WCGS PRA model was provided in Attachment I to the licensee's application. The licensee stated that the PRA updates are an ongoing process and the revision date for the PRA updates refers to the cutoff date for the consideration of plant data when updating the model. The licensee explained that this means the 1998 PRA update for WCGS began in 1998 and considered new plant data up to that date. The 1998 update was completed and approved by the last half of 1999, and this is the model of record at the time of the submittal of the application for this amendment.

The peer review identified two level A Facts and Observations (F&Os), one related to the modeling of transients for which the Essential Service Water (ESW) pumps do not receive an automatic start signal and the other related to plant data collection. The licensee evaluated both these A level F&Os. The licensee stated that the ESW pump F&O is not applicable to the evaluation to extend the CT time. In the supplemental letter dated March 6, 2006, the licensee stated that the conclusions of the PRA evaluation to support the extension of the CT time would not change with the inclusion of more recent plant data. The licensee further reported one F&O related to estimating the loss of station power (LOSP) initiating event frequency that had the potential to impact the evaluation to extend the CT time. The licensee described how the LOSP frequency for use in the PRA was modified to include LOSP events up through 2002, and reflect the weather condition expected during the calendar interval where the extended AOT for DG maintenance may be used.

The licensee discussed three other changes that were made to the PRA in support of the evaluation of the change in risk associated with extending the DG CTs. One change was an increase in the DG mission time from 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months used in the IPE to 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months , in order to provide consistency with most other internal events PRA models. The other two changes involved a change to the reactor coolant pump (RCP) seal LOCA model and the addition of an evaluation of the availability of the Sharpe Station generator.

The licensee estimated the availability of the Sharpe Station generator sets to provide sufficient power to support one safety bus with LOCA loads, given that the TS-required preparations are in place at the Sharpe Station. The analysis included blackstart of at least four of ten of the Sharpe Station diesels and successful transfer of greater than 8 MW power to a dead safety bus.

Representatives of the WCNOC PRA group, along with other WCNOC personnel, visited the Sharpe Station several times with the utility engineer responsible for the Sharpe Station. A PRA

model for the Sharpe Station was developed based on these visits to the station and discussions with the utility engineer responsible for the station. The Sharpe Station model was reviewed by a second, independent WCNOC PRA analyst, and by a group engineer. This followed the regular calculation approval process used for Engineering and safety analysis. The licensee did not incorporate the Sharpe Station into the PRA but described how the risk impact of the station was incorporated into the reported PRA results. As discussed below, the licensee has committed to include the risk impact of the Sharpe Station in the safety monitor to support the Tier 3 evaluations prior to the first utilization of the extended DG CT. The licensee has explained that the changes to SSC failure probabilities due to performance issues found under the Maintenance Rule is reflected in real time in the safety monitor, which provides current risk numbers for plant configurations based on the PRA model.

In Attachment II to its supplemental letter dated August 31, 2005, the licensee stated that external events considered in the Individual Plant Examination of External Events (IPEEE) for WCGS were, for the most part, evaluated against screening criteria specific to each event in accordance with methodologies listed as acceptable in Generic Letter (GL) 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f)," Supplement 4, dated June 28, 1991. The licensee evaluated the potential impact on the risk estimates due to external events as described below.

The licensee has evaluated the relevant F&Os from the WOG peer review and addressed the F&Os whose resolution could affect the PRA results reported in support of this amendment request. The licensee has also developed the appropriate PRA models for the Sharpe Station through visits to the station and discussions with appropriate personnel. These models have been reviewed according to the licensees regular calculation approval process. Based on its review of the licensee's evaluation discussed above, the NRC staff concludes that the quality of the WCGS PRA model is sufficient to support the request to extend the DG CT.

3.3.1.1.2 PRA Insights Estimated Risk Increase The licensee provided the values of CDF, LERF, the changes in CDF and LERF, ICCDP and ICLERP based on the PRA model for the proposed extended CTs in Attachments I and II to its application. The values taken from Attachment I (pages 15 and 17 of 23) and Attachment II (pages 13, 14, and 21 of 24) to its application are given in the table on the next page.

Summary of Impact on Risk of Extended DG CTs Parameter Extended DG CT From 72 Hours to 7 Days CDF for base case 3.48E-05/year Change in CDF 4.56E-07/year

Summary of Impact on Risk of Extended DG CTs LERF (base case) 7.73 E-07/year Change in LERF 1.07E-08/year ICCDP* 4.56E-07 ICLERP* 1.07E-08 Notes: * = The DG is in test or scheduled maintenance.

The licensee stated that, with regard to the Sharpe Station, a simple examination of the first several cutsets quickly identifies the single dominating basic event, which is failure of the assumed operator action to properly energize and align the Sharpe Station to the WCGS switchyard for use to mitigate a SBO event. This event is nearly two orders of magnitude greater than the next most significant cutset, the common cause failure (CCF) of all the gensets to run. A common cause term is included for each genset at the Sharpe Station and these terms are combined in the fault tree logic to obtain failure combinations. Individual terms were developed for 2 out of 5 gensets, 3 out of 5 gensets, 4 out of 5 gensets, and 5 out of 5 gensets, with the probability of 5 out of 5 gensets assumed to be equal to the probability of all gensets (there are 10 gensets at the station) being unavailable. The licensee stated that this a conservatism has significant impact to this evaluation because it results in the second largest cutset generated.

The licensee further explained that the basis for the assumed operator action value used in this evaluation is engineering judgment and, following the application, a separate human reliability analysis (HRA) evaluation was performed based on the availability of the procedure for use in aligning the Sharpe Station to provide mitigation of a SBO event. This evaluation produced an operator action value of nearly one order magnitude less than the value used for the application.

The licensee concluded that due to the level of conservatism assumed for the dominating operator action, a sensitivity study on any other aspect of taking credit for the Sharpe Station in this amendment request would not yield useful results.

Because the risk estimates provided by the licensee for the proposed extended DG CT are less than the risk guidelines in RGs 1.174 and 1.177, the NRC staff concludes that they are acceptable. As described above, the licensee identified several of the greatest contributors to uncertainty in the risk estimates and evaluated the sensitivity of the estimates on the assumptions and addressed the realism or conservatism of the assumptions. Based on this, the NRC staff concurs that the evaluations demonstrate that the estimated values are reasonable and most likely somewhat conservative.

External Events The licensee addressed the potential impact of extending the DG CTs on risk caused by fires in its supplemental letter of March 6, 2006. The licensee stated that the alignment for delivery of power from the Sharpe Station to either or both ESF buses at WCGS is through ESF transformer XNB01. The fires that would impact XNB01, or the supply cables from XNB01 to ESF buses NB01 or NB02, would prevent delivery of power from the Sharpe Station to WCGS. However, all of the fire areas impacting XNB01, or the supply cables from XNB01 to NB01 or NB02, were

screened out in the fire risk evaluation performed for the IPEEE using the EPRI FIVE methodology (i.e., a full PRA of the fire area was not required).

For the fire areas impacting XNB01, or the supply cables from XNB01 to NB01 or NB02, the conditional core damage probability (CCDP) was re-quantified with the unavailability values for the DGs adjusted to account for the extended CTs and, using the re-quantified CCDP, the frequency of core damage due to a fire in the area was determined in accordance with the methodology of the original fire risk evaluation. For all of these fire areas, the core damage frequency due to a fire in the area using the re-quantified CCDP, met the screening criteria using the EPRI FIVE methodology. For fire areas where XNB01, or the supply cables from XNB01 to NB01 or NB02, are not impacted, the delivery path for power from the Sharpe Station to either or both ESF buses would remain available. The licensee concluded that, for fire areas where the delivery path for power from the Sharpe Station to either or both ESF buses remain available, the risk benefit realized from having the Sharpe Station power supply available more than offsets the risk increase due to the extended DG CT.

The licensee also addressed the potential impact of extending the DG CTs on risk caused by seismic events in its supplemental letter of March 6, 2006. The licensee stated that it performed a reduced Scope seismic analysis for the IPEEE and plants that fall under reduced Scope are in the lowest seismic zone and the probability of a seismic event at WCGS is very low. An extended DG CT does not appreciably increase the risk of core damage due to a seismic event. The licensee addressed the remaining external events by explaining that the WCGS site is situated such that external flooding does not present an appreciable amount of risk to the plant, and the impact of weather on the plant has been accounted for in the regulatory commitment listed in the application (see commitment 4 in Section 4.0 of this SE). The licensee further stated that the Tier 2 restrictions (see Section 3.3.1.1.3 of this SE) would be added to the TS Bases and the impact of weather will be incorporated with the changes to the safety monitor (discussed in Section 3.3.1.1.1 of this SE).

Based on the discussion above, the NRC staff concurs that the evaluation of external events described above satisfactory demonstrates that any increase in risk caused by the extended DG CT would not appreciably contribute to the estimates provided.

Cumulative Risk In Attachment II to its supplemental letter dated August 31, 2005, the licensee addressed the cumulative risk impact from two previous risk-informed submittals of the same type (i.e., submittals proposing changes to CTs in the TSs). These previous submittals for WCGS requested (1) an increased CT for accumulators and (2) changes to the CT, test bypass times, and surveillance frequency for reactor trip system (RTS) and engineered safety feature actuation system (ESFAS) instrumentation. These changes were approved in Amendment Nos. 124 and 156 issued April 27, 1999, and January 31, 2005, respectively.

The licensee stated that the estimated CDF increase from the increased CT for the accumulator is 3.60E-08/year. There was no estimate of the potential impact on LERF, but the LERF increase would be negligible given the small increase in CDF. The licensee further stated that the cumulative CDF and LERF increases for the RTS and ESFAS Instrumentation changes and the CT extension are 1.54E-6/year and 6.65E-8/year respectively. Summing these previous risk increases with the increase caused by the increased DG CT proposed in this submittal results in a

total increase in CDF and LERF of 2.03E-6/year (3.60E-8/year + 1.54E-6/year + 4.56E-7/year) and 7.72E-8/year (6.65E-8/year + 1.07E-08/year) respectively.

The cumulative LERF increase of 7.72E-8/year falls below the 1E-7/year threshold placing in in the Very Small region [Region III] of Figure 3 in RG 1.174. The cumulative CDF increase of 2.03E-06 falls marginally above the 1.0E-06 threshold placing it in the Small Changes region

[Region II] of Figure 3. For this region, a closer assessment of the baseline CDF is indicated. In Attachment II to its supplemental letter dated August 31, 2005, addressing external events and fires, the licensee stated the following:

For the most part, external events considered in the IPEEE were evaluated using screening criteria specific to each event in accordance with methodologies in Generic Letter 88-20, Supplement 4. For all external events except fire, [the]

evaluation indicated low risk significance and the events were screened out. For fire areas that did not screen out using the progressive screening of the EPRI Fire-Induced Vulnerability Evaluation (FIVE) methodology, quantitative evaluations using conventional PRA approaches [were] performed. For the unscreened fire areas, the quantified CDF due to fire was 7.59E-06, which was approximately 15% of the internal events CDF determined in the IPE. In 1998, the fire risk evaluation was revisited, using the same methodology, with a resultant quantified CDF due to fire of 8.14E-06. This represented approximately 13% of the internal events CDF of 6.31E-05 for the PRA model current at the time the fire risk was evaluated. The fire risk evaluation has not been updated subsequent to the 1998 time frame.

The fire risk evaluations performed indicate a contribution due to fire that represents less than 20% of the internal events CDF. The remaining external events met the appropriate associated screening criteria and may be considered to be of low safety significance. If the baseline internal events CDF of 3.485E-05, from the PRA model used to evaluate these Completion Time extensions, were increased by 50% to conservatively account for contributions due to external events, the total baseline CDF (5.23E-05) would still remain well below the Region II upper bound CDF of 1.0E-04 from Figure 3 in RG 1.174.

Because the total baseline CDF value is expected to be well below 1.0E-04; and given that the cumulative CDF increase of 1.543E-06 is only marginally above the Region II lower bound of 1.0E-06, the licensee concluded that the cumulative CDF impact is acceptably small for the proposed amendment.

Based on the discussion above, the NRC staff concurs that the evaluation of cumulative risk described above satisfactory demonstrates that any increase in risk caused by the extended DG CT would not appreciably contribute to the estimates provided.

Combined Change Request The licensee proposed changes to the TSs that (1) enable the Sharpe Station to be used as a backup power source to power a dead safety bus and (2) extend the DG CT from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 7 days. The increase in risk associated with these combined changes is discussed extensively and is compared to the guidelines in 1.174 to support the acceptability of the proposal.

To quantify the benefit of the changes enabling the Sharpe Station to be used as a backup power source, the licensee also provided the following CDF and LERF values for with and without the Sharpe Station being credited:

Sharpe Station Normal Protected Being Credited CDF 3.485E-05 5.170E-05 LERF 7.735E-07 1.169E-06 Not Being Credited CDF 5.173E-05 1.563E-04 LERF 7.796E-07 1.354E-06 The licensee stated that "Normal" refers to everyday operation configuration of WCGS with no specific compensatory measures in effect, such as those described in Section 3.3.1.1.3 of this SE on Tier 2 Considerations. "Protected" refers to a plant configuration implementing the compensatory measures as described in Section 3.3.1.1.3 of this SE.

Based on the above table, the CDF and LERF estimates without the Sharpe Station being a backup AC source (i.e., Sharpe Station Not Being Credited) are consistently higher than for the changes being made to have the Sharpe Station as a backup AC source (i.e., Sharpe Station Being Credited). Changes that decrease risk clearly meet the acceptance criteria in RG 1.174.

Because the availability of the Sharp Station before entering the extended DG CT is required by the TSs, estimates of the risk increase associated with the extended DG CT without credit for the Sharpe Station are not meaningful and need not be evaluated.

RCP Seal Model During the NRC review of WCAP-15603, "WOG2000 Reactor Coolant Pump Seal Leakage Seal Model for Westinghouse PWR [pressurized water reactors]," the NRC staff concluded that the PRA results can be sensitive to the reactor coolant pump (RCP) seal model employed in a PRA and that the licensee should document their RCP model in the submittal. In its supplemental letters dated August 31, 2005, and April 14, 2006, the licensee stated that, in preparation for the amendment application, the PRA model for the RCP seal leakage parameters were updated to the parameters associated with the installation of high temperature, qualified seal materials for all RCPs. The parameters were obtained from the Brookhaven National Laboratory Technical Report W6211-08/99, "Guidance document for Modeling of RCP seal failure," dated August 1999.

Since its application for this amendment, the licensee has been in the process of updating the PSA model, including an updated RCP seal model using WCAP-15603, Revision 1, and stated that it expects to have this model completed in the near future. The updated PSA Model is referred to by the licensee as the 2002 WCGS PSA Model. The licensee stated that after it completed 2002 WCGS PSA it would then verify that the use of the Sharpe Station in the PSA, to support the proposed amendment, continue to meet the acceptance guidelines of RGs 1.174 and 1.177 before it used the amendment to have a DG in an extended CT for planned maintenance.

The licensee addressed the estimated risk increases due to the proposed amendment, but with the PSA model not including the WCAP-15603 RCP seal model in the beginning of Section 3.3.1.1.2 of this SE. The licensee made this update of the PSA model a regulatory commitment (See Attachment II of the supplemental letter dated April 14, 2006) and has proposed a license condition to added to the operating license with the approval of this proposed amendment. Based on the license condition to update the PSA model and verify that the proposed extension of the DG CT continues to meet the acceptance criteria of RGs 1.174 and 1.177 before the license would use the extended DG CT, the NRC staff concludes that the licensee has acceptably addressed the RCP seal model in the WCGA PSA model.

3.3.1.1.3 Conclusions The risk estimates provided by the licensee for the proposed extended DG CT are less than the risk guidelines in RGs 1.174 and 1.177. The NRC staff concurs that the sensitivity evaluations performed by the licensee demonstrate that the estimated values are reasonable and most likely somewhat conservative. The NRC staff concurs that the evaluation of external events described above satisfactory demonstrates that any increase in risk caused by the extended DG CT would not appreciably contribute to the estimates provided. Therefore, the NRC staff concludes that the licensee has acceptably addressed the Tier 1 consideration for the proposed amendment.

3.3.1.2 Tier 2 Considerations For Tier 2, the licensee identified the following additional compensatory measures that will apply when the plant enters the proposed planned extended DG CT:

Perform work during a favorable weather period (September 6 through April 22).

Check the weather forecast for severe weather conditions.

Preclude elective testing and maintenance activities in the switchyard that could cause a power line outage or challenge offsite power availability.

Check that the Sharpe Station gensets are available and their performance is acceptable.

Concurrent work on other key SSCs (i.e., the essential service water system, component cooling water system, motor/turbine auxiliary feedwater pumps, and residual heat removal system) is not planned during the extended DG CT.

Additional elective equipment maintenance or testing that requires equipment to be removed from service during the extended DG CT will be evaluated and activities that would cause unacceptable results will be avoided.

It should also be pointed out that the licensee has proposed a note for the TSs that limits the extended CT for only planned maintenance and once per DG per operating cycle. Therefore, the DG would not be in the extended CT for repairs or more than once an operating cycle. These conditions would be required by the proposed note in the TSs.

Based on the above, the licensee concluded that there is reasonable assurance that risk-significant plant configurations will be avoided when a DG is removed from service to perform on-

line maintenance during the extended CT. The licensee stated that the assurance would be provided by TS requirements and the above Tier 2 restrictions, which the licensee has identified will be included in the TS Bases. Also, these Tier 2 restrictions were submitted by the licensee as regulatory commitments. See Section 4.0 of this SE. Based on its review, the NRC staff agrees with the conclusion of the licensee and concludes that the licensee has acceptably addressed Tier 2 considerations for the proposed amendment.

3.3.1.3 Tier 3 Considerations For Tier 3, the licensee stated that the objective of Tier 3 is to ensure that the risk impact of out-of-service equipment is evaluated prior to performing any maintenance activity. Tier 3 is an extension of Tier 2 and addresses the possibility of not being able to identify all possible risk-significant plant configurations in the Tier 2 evaluation. The licensee stated that the risk impact of the Sharpe Station is currently not in the safety monitor, but it will be included in the safety monitor prior to the first utilization of the extended DG CT. As discussed below, the licensee made this regulatory commitment in its supplemental March 6, 2006, letter and this is addressed in Section 4.0 of this SE.

The risk impact associated with the performance of equipment testing and maintenance activities is evaluated in the WCGS Operational Risk Assessment Program (ORAP), administrative procedure AP 22C-003, the plant-specific CRMP. The ORAP assesses the risk associated with both planned and unplanned work activities, and, being part of the Maintenance Rule, operates at all times to manage the risk during maintenance at the plant. The licensee explained that an operational risk assessment (ORA) is performed to assess the risk of performing activities within a weekly schedule and compensatory measures are considered for risk significant activities. An ORA would be performed on the work to be performed on the DG within the extended CT. The ORAP addresses the impact on the ORAs due to added or emergent work, or work that has slipped from its scheduled completion time. The ORAs are reviewed by the WCGS PRA group and approved by the plant manager. The licensee explained that the above Tier 3 considerations address the risk of on-line maintenance of a DG in an extended CT.

In its March 6, 2006, letter, the licensee explained that the guidance regarding assessment and risk management prior to the performance of maintenance at Wolf Creek is controlled by procedure AP 22C-003, Operational Risk Assessment Program. The risk assessment process includes a PSA group review of the weekly work schedule and performance of a quantitative risk assessment using what the licensee called the "safety monitor," approximately one week prior to the work being performed. The PSA group signs the IPS assessment, provides a risk profile for the weeks activities and any recommendations based on their insights to IPS. Implementation of the safety monitor at WCGS included development of a LERF top logic model in 1997 to import the PRA model into the monitor. Also, a limited scope shutdown mode PRA model was developed as part of the safety monitor. The NRC staff identified that the licensee's safety monitor needed to include the Sharpe Station when the Sharpe Station was being credited as an alternate AC power source during an extended DG CT (see Section 3.3.2.2 of this SE).

The licensee stated that the inclusion of the risk impact of the Sharpe Station in the safety monitor will be accomplished prior to the first utilization of the extended DG CT. It stated that an activity will be added to the activity table of the safety monitor that will account for the impact of the plant configuration associated with crediting the Sharpe Station, which will adjust the SBO event value and reduce the LOOP initiating event frequency to reflect the weather conditions expected during

the calendar interval where the extended CT for DG maintenance is used. The licensee explained that, with the addition of this activity to safety monitor, the configuration-specific risk (i.e., Tier 3) will be properly reflected by taking the appropriate DG out of service and will allow the determination of the risk for other potential combinations of equipment removed from service or emergent plant conditions for the time period of the extended DG CT (i.e., the Tier 3 evaluation).

In addressing the NRC question on the CRMP and whether it meets the key components guidance in Subsection 2.3.7.2 in RG 1.177, the licensee stated, in its letter dated March 6, 2006, that the CRMP includes these key components and implements the requirements of 10 CFR 50.65(a)(4) that requires licensees, prior to performing maintenance activities, to assess and manage the increase in risk that may result from the proposed maintenance activities. The requirements and expectations for performing the risk assessments are given in Procedure AP 22C-003, Operational Risk Assessment Program. A corrective action document would be generated for all equipment failures and the Shift Manager is responsible for evaluating how changing conditions (including new equipment issues) impact the plant and work in progress, including the risk associated with the condition. The Shift Manager has several options available to evaluate the risk associated with changing conditions, including performing a qualitative assessment based on his/her knowledge and experience, using the safety monitor to assess the risk or requesting assistance from the PSA group.

Based on the above, the NRC staff concludes that the licensee has acceptably addressed Tier 3 considerations for the proposed amendment.

3.3.1.4 Implementation and Monitoring Program RG 1.174 states that an implementation and monitoring plan should be developed to ensure that the impacts of the proposed risk-informed amendment continue to reflect the actual reliability and availability of the SSCs evaluated to support the proposed CT extensions. The licensee stated that it has established three performance goals to monitor the performance of the DGs in conformance with the 10 CFR 50.65, the Maintenance Rule. These goals include determining the unavailability, reliability, and the number of functional failures, in the most recent 25 demands.

Monitoring performance in accordance with the Maintenance Rule can be used when such monitoring is sufficient for the SSCs affected by the risk-informed amendment applications. The NRC staff finds that these performance measurements adequately track the actual reliability and availability of the DGs and, based on this, concludes that they satisfy the monitoring guidelines of RG 1.174.

3.3.1.5 Conclusion Based on its evaluation of the quality of the WCGS PRA model and the changes made to the PRA model in updating the model and in accounting for the proposed amendment, the NRC staff concludes that the use of the WCGS PRA model to calculate the CDF, LERF, ICCDP, and ICLERF values for the proposed extended DG CT is acceptable. Because the values of the CDF, LERF, ICCDP, and ICLERF values presented by the licensee for the proposed extended DG CT meet the risk guidelines in RGs 1.1.74 and 1.1.77, the NRC staff further concludes that proposed extended CTs for an inoperable DG are acceptable from the aspects of the risk in the licensee going to the proposed 7-day extended CT for the DGs.

3.3.2 Deterministic Review

In its deterministic review of the proposed amendment to extend the DG CT, the NRC staff reviewed on-line post-maintenance testing of a DG, the comparison of the Sharpe Station gensets to an AAC source of AC power as it is defined in RG 1.155, and the licensee's use of crossties and cross-connecting of safety buses. These review areas are addressed below.

3.3.2.1 On-Line Post-Maintenance Testing of DG in an Extended CT First, the work on the DGs in the proposed extended CTs is for planned maintenance to maintain DG operability, not for repairs to return the DG to operability. Therefore, going into the extended CTs, there is every reason to expect that the DG is operable and, even though the process of performing the maintenance will make the DG inoperable, that it will be returned to operability upon completion of the maintenance. The post-maintenance testing is the verification that the DG has been returned to operable status.

The licensee addressed the on-line maintenance of a DG in an extended CT in its responses to (1)

RAI 11 in Attachment II to its application and (2) RAIs 31 through 33 in Attachment I and the question in Attachment III, to its supplemental letter dated August 31, 2005. In its responses, the licensee pointed out that Amendment 154 issued July 12, 2004, approved conducting the following tests or portions of tests of the DGs in Modes 1 and 2: the full load rejection test, the protective relay bypass test, and the endurance and margin test. The licensee stated that the required scope of post-maintenance testing, and the degree that this testing provides a high level of assurance of DG operability following DG maintenance, is dependent on the DG maintenance performed. The intent of the post-maintenance testing is to sufficiently challenge the DG in order to verify DG performance following maintenance. The licensee stated that, in general, for most maintenance activities to be performed on DGs, the start-and-load test, which is routinely performed on a monthly basis, is typically all that is required to demonstrate operability of the DG following maintenance. The licensee stated that this is true even for significant tear-downs and inspections of the DGs, and experience has shown that this test is capable of detecting the most likely failure modes and maintenance errors. The testing per other SRs in the TSs verifies the widest spectrum of the various DG design aspects, but many of these tests overlap in scope and for the most part the additional testing is not likely to reveal failure modes that the start-and-load testing would not identify. The licensee concluded that the start-and-load testing provides sufficient testing of the DG to demonstrate the DG operability following an on-line maintenance of the DG. Based on its review of this amendment, the NRC staff concurs with this conclusion by the licensee.

In a communication to the NRC staff, the licensee stated that the start-and-load test, discussed above, is performed to verify that each DG starts from standby conditions and achieves certain specified voltage/frequency conditions (1) in less than or equal to 12 seconds and (2) at steady state. This test is SR 3.8.1.7, which has a quarterly surveillance test interval and is conducted on-line. Therefore, the post-maintenance testing of the DG to demonstrate operability is an SR in the TSs that is allowed to be conducted on-line. The NRC staff agrees with the licensee that SR 3.8.1.7 can be conducted on-line following DG maintenance and is sufficient to demonstrate the DG is operable following maintenance.

Based on the above, the NRC staff concludes that it is safe to operate the plant and conduct planned DG maintenance on-line in an extended CT with the above post-maintenance start-and-load test being conducted on-line to demonstrate DG operability.

3.3.2.2 Compare Sharpe Station Gensets to an Alternate AC (AAC) Source per RG 1.155 An AAC is defined in RG 1.155. The licensee listed the AAC design criteria in its response to question RAI 5, in Attachment II to its application. The AAC design criteria are the following:

10. The AAC power source should not normally be directly connected to the preferred or the blacked-out unit's onsite emergency AC power system.

11. There should be a minimum potential for CCF with the preferred or the blacked-out unit's onsite emergency AC power system. No single-point vulnerability should exist whereby a weather-related event or single active failure could disable any portion of the blacked-out unit's onsite emergency AC power system or the preferred power sources and simultaneously fail the AAC power source.

12. The AAC power source should be available in a timely manner after the onset of SBO and have provisions to be manually connected to one or all of the redundant safety buses as required. The time required for making this equipment available should not be more than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months as demonstrated by test. If the AAC power source can be demonstrated by test to be available to power the shutdown buses within 10 minutes of the onset of SBO, no coping analysis is required.

13. The AAC power source should have sufficient capacity to operate the systems necessary for coping with an SBO for the time required to bring and maintain the plant in safe shutdown.

14. The AAC power source should be inspected, maintained, and tested periodically to demonstrate operability and reliability. The reliability of the AAC power source should meet or exceed 95 percent as determined in accordance with NSAC-108 or equivalent.

The licensee discussed the AAC power source for WCGS for the proposed extension of the DG CT, and compared the source to the RG 1.155 criteria, in its response to RAI 5 in Attachment II to its application. The licensee stated that the AAC is the 10 units of 2-megawatt Caterpillar 3516B engine-generator-sets (gensets) at the Sharpe Station, which is located 2 miles north of the plant site. The licensee has determined that 4-out-of-10 gensets are required to support one safety bus with LOCA loads.

The licensee further stated that the gensets have been modified for blackstart. Power from these gensets would enter the WCGS switchyard by the existing Phillips 69 kV line that is lightly loaded and radially fed from the WCGS 69 kV substation. The logic for breaker 69-4 will have to be modified to allow the breaker to be closed with the Phillips 69 kV line side energized and the 69 kV bus de-energized. This would be the situation in SBO when AC power from the Sharpe Station gensets would be needed at WCGS and the breaker permissive logics did not allow for this situation. The breaker logics had to be modified to accommodate the conditions in SBO to provide power from the Sharpe Station to WCGS when the line side would be energized, but the bus side would be de-energized. Therefore, the existing breaker 69-4 does not allow for the Sharpe Station gensets to be connected to the WCGS safety busses. In its application, the licensee made a commitment to complete this modification prior to the implementation of the amendment. The commitment is addressed in Section 4.0 of this SE.

The licensee stated that the Sharpe Station is owned and operated by Kansas Electric Power Cooperative, Inc. (KEPCo), one of 3 owners of the WCGS. There is an operating agreement between KEPCo and the licensee for the use and maintenance of the Sharpe Station. Power from the Sharpe Station enters the WCGS switchyard by the Phillips 69-kV line, which is lightly loaded.

Because the licensee is not proposing the Sharpe Station for SBO, the above criteria for an AAC for SBO should be more restrictive than the criteria that would be necessary for allowing the licensee to have a DG out-of-service for maintenance while relying on the Sharpe Station as another AC power source to power an ESF bus.

In the licensee's review of the Sharpe Station gensets with respect to the RG 1.155 AAC criteria, the licensee concluded that it met criteria 1 and 4 above.

For Item 2, the licensee stated that it addressed the vulnerability of the licensee's reliance on the Sharpe Station, including CCF and weather-related events. The licensee stated that no commonalities exist between the DGs and the Sharpe Station gensets, and the representation of the Sharpe Station in the WCGS PRA model includes CCF terms in the fault trees. In its response to RAIs 24 and 25 in Attachment I to the supplemental letter dated August 31, 2005, the licensee stated that the 69 kV line can be aligned to be common between the Sharpe Station and WCGS, but this is not typical. The gensets are peaking units, generally not connected to the grid (i.e., the 69 kV line) and would be used during periods of challenging high load conditions on the grid. The WCGS DGs are Fairbanks Morse-Colt Pielstick PCV2.5 design and the gensets are Caterpillar 3516B design, which have no design commonalities For severe weather events, the licensee stated that it intends to perform DG maintenance during historical time frames of low severe weather frequency and, prior to planned DG maintenance, the licensee would check the weather forecast for severe weather predictions. Also, the licensee has procedures concerning severe weather whereby it maintains awareness of any threatening weather conditions. The licensee identified administrative controls would be applied during DG maintenance concerning having weather and switchyard conditions conducive to the extended DG CT before starting DG maintenance in the TS bases changes submitted with the application. The licensee also made such regulatory commitments in its application. Based on this, the Sharpe Station meets the intent of Item 2 with respect to extending the inoperable DG CT.

For Item 3, the licensee stated that the AC power from the Sharpe Station will be available without delay; however, the not more than 1-hour time period for SBO is too severe for the present situation of an extended DG CT. The DG maintenance would be a scheduled and planned maintenance and appropriate contacts would be made to take action in a timely manner. By conference call on July 25, 2005, the licensee stated that an operator would be sent from WCGS to the Sharpe Station to start the four gensets. The estimated time to travel the distance to the Sharpe Station and start the gensets is 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months (this was addressed in the response to NRC question No. 3 in the licensee's supplemental letter dated March 6, 2006). In the identified TS Bases changes, the licensee stated that it would have administrative controls to have the Sharpe Station available and able to provide greater than 8 MW power to power one ESF train before taking the DG out-of-service for maintenance. Based on this, the Sharpe Station meets the intent of item 3 with respect to extending the inoperable DG CT.

For item 5, the licensee stated that KEPCo, which operates the Sharpe Station, has an operating agreement with WCGS to maintain the gensets with the manufacturer's recommendations and

prudent utility practice. Maintenance runs are performed on each genset on a monthly basis. The WCGS plant has priority dispatch status in the event of emergent inoperability of a DG or a complete loss of all Wolf Creek emergency AC power. In addition, the licensee stated that it would be notified when the Sharpe Station unit capability is determined to be less than 50 percent of design capacity. Performance information, such as status of each genset, is determined daily, and component failures of the gensets and supporting electrical switchyard gear will be available to WCGS. Also, prior to taking a DG out-of-service for maintenance, the licensee is required by administrative controls to determine, as described in the discussion of item 3, that the Sharpe Station is available and able to provide greater than 8 MW power for one ESF train.

In its response to RAI 9 in Attachment I to its supplemental letter dated August 31, 2005, the licensee stated that a simplified one-line drawing of the Sharpe Station AC power to WCGS is shown in the figure on the bottom of page 5 of 23 in Attachment I of its application. The licensee stated that in the event of an SBO, the figure illustrates the connection of the Sharpe Station through the WCGS switchyard and onto safety bus XNB01. Operator action is included as a generic, top-level, event in the Sharpe Station fault tree with a value of 0.035. With two dead busses, bus XNB01 may be used to feed the Sharpe Station AC power over to bus NB02. Also, the licensee explained further that training with operations personnel has been conducted on the Sharpe blackstart draft procedure, including walkdowns of the gensets and electrical busses.

The licensee addressed training in its response to NRC Question 3 in its supplemental letter dated March 6, 2006, in that it stated that it has developed a procedure in conjunction with KEPCo personnel for aligning the Sharpe Station with the WCGS switchyard. It also has provided training to the operating crews on this procedure. Training is scheduled for the standard two-year rotation.

The licensee explained that prior to performing the preplanned maintenance activity on a DG, a pre-job brief is performed in accordance with its procedure on conducting a pre-job brief. Its procedure requires a thorough pre-job brief, including a management brief to be performed for infrequent high-risk tasks. Additional pre-job briefs are held for activities that continue into the next shift. It is WCGS Operations practice for high-risk infrequently performed evolutions and tasks to perform a walkdown of the procedure prior to the performance of the activity and to have management briefings to provide oversight of infrequently performed tests or evolutions.

The RG 1.155 criteria do not address the situation if, during DG maintenance, the 4-out-of-10 gensets are no longer available and DG maintenance has not been concluded. The proposed TS 3.8.1, Required Action B.5 requires that, if the gensets at the Sharpe Station are not available to provide 8 MW of power, the licensee has 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months from that point in time to restore the DG being maintained to operable status or start shutting the plant down.

The licensee also addressed the vulnerability of the Sharpe Station as an AAC in terms of CCF mechanisms and external events in its response to RAI 7 in Attachment II to its application.

Concerning common cause mechanisms, the licensee stated that there are no commonalities between the WCGS DGs and the Sharpe Station gensets. For external events, severe weather that impacts the WCGS switchyard could affect the Sharpe Station, which is located 2 miles north of the WCGS site. However, maintenance of the DGs using the extended DG CT would be conducted in historical time frames of low severe weather frequency, the weather forecasts would be checked for severe weather predictions before such maintenance would be started, and the proposed TSs would require periodic verification of the availability of the gensets at the Sharpe Station. For external events involving flooding and transportation, the Sharpe Station is located away from major highways and water sources.

Only 4 out of 10 gensets are needed to provide sufficient AC power to a WCGS vital AC safety bus when the DG is in an extended CT for planned maintenance.

The licensee stated in response to an NRC question that a steady-state voltage drop analysis, coupled with a start of the largest motor load, will be performed with four gensets connected to one safety bus and the analysis demonstrated that voltages are adequate to maintain safety-related equipment running and adequate voltage is available to the motor control centers to prevent contactor or relay drop out. The gensets at the Sharpe Station would be maintained consistent with the manufacturers recommendations and prudent utility maintenance practices and maintenance runs are performed on each genset on a monthly basis. Because the Sharpe Station gensets were added for commercial reasons by KEPCo, the gensets are utilized (loaded) on an as-needed basis. To qualify/credit the Sharpe Station gensets as peaking units and to meet the Southwest Power Pool requirements, maximum capability tests were run with all 10 units running in parallel. These capability tests were run during the hottest day of the summer and the substation output power was measured at 19.3 megawatts. These capability tests are run approximately every three years and all 10 units were run for load for 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , in mid-December 2005, confirming the substations 20 megawatt output capacity.

In its supplemental letter dated March 6, 2006, the licensee addressed the capability of the Sharpe Station to start emergency loads at WCGS. This will be demonstrated by the following two tests of the Sharpe Station gensets: (1) a one-time load acceptance test to demonstrate the capability of the Sharpe Station to successfully start a large motor to simulate nuclear plant loads and (2) a periodic load capability test/verification by either crediting a running of the gensets for load for commercial reasons or by loading of the gensets for greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to a load greater than required to supply safety-related loads in the event of an SBO.

For the first test, the licensee stated that it will perform a one-time load acceptance test of the Sharpe Station prior to the first use of the 7-day CT for preplanned maintenance activities (per the note to TS 3.8.1 Required Action B.4). The test will demonstrate the capability of the Sharpe Station to successfully start a large motor (a 1500 hp motor at a nearby gas pumping station) to simulate the gensets carrying the worst case step loading of nuclear plant loads at WCGS and validate the flow analysis to predict frequency and voltage for full load analysis. Additionally, using the validated software, a dynamic voltage flow analysis would be performed for the maximum designated loads on the train, using vendor provided test data for starting large motor loads, to further demonstrate from an analysis perspective that the Sharpe Station would be capable of starting and carrying designated loads, including maintaining adequate voltage and frequency such that the performance of powered equipment would be acceptable. The licensee explained that this means that the analysis will demonstrate that the gensets are capable of starting and carrying designated loads and that the voltage and frequency would be adequate to ensure no damage to equipment and that degraded voltage and loss of voltage functions are not challenged. It further stated that this analysis would also demonstrate that no additional gensets are required to supply safety-related loads. This is Commitment No. 8 discussed in Section 4.0 of this SE.

For the second test, the licensee stated that there would be a load capability testing/verification of the Sharpe Station gensets performed within 8 months prior to each utilization of the 7-day extended DG CT. The load capability testing/verification would consist of either (1) crediting a running of the gensets for load for commercial reasons for greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or (2) a test by loading of the gensets for greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to a load equal to or greater than required to supply

safety-related loads in the event of an SBO. The licensee stated that it would coordinate with KEPCo to ensure either of these tests are done before the licensee entered TS 3.8.1 Required Action B.4.2.2. This is Commitment No. 6.c discussed in Section 4.0 of this SE.

The licensee has proposed these tests as requirements in the license. This is addressed in Section 4.0 of this SE.

The licensee further explained that eight of the ten gensets have an underbelly fuel storage tank suitable of fueling the genset for a minimum of 27 hours3.125e-4 days 0.0075 hours 4.464286e-5 weeks 1.02735e-5 months of operation. The remaining two units have fuel capacity for a minimum of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Additional fuel is available from a vendor that can be trucked in on an as-needed basis. Additional fuel would be brought to the Sharpe Station in a 4700 gallon capacity tanker. It was stated that discussions between the fuel oil vendor and KEPCo indicated that the fuel oil could be delivered in approximately 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . Because the Sharpe Station has no other on-site diesel fuel storage, the licensee stated that it will coordinate with KEPCo to ensure that a fuel oil vendor is available to provide fuel oil to the Sharpe Station on an as-needed basis. This is regulatory commitment no. 5 discussed in Section 4.0 of this SE.

Based on this and how the Sharpe Station gensets compare to the AAC design criteria in RG 1.155, and the proposed TS 3.8.1 changes to address the Sharpe Station, which are discussed above, the NRC staff concludes that the Sharpe Station gensets are acceptable as an AAC for a DG in an extended CT for WCGS.

3.3.2.3 Crossties and Cross-Connecting of Safety Buses In its response to RAI 9 in Attachment I to its supplemental letter dated August 31, 2005, the licensee stated that it was taking no credit for crossties or cross-connecting of safety buses.

3.3.2.4 Conclusion Based on its evaluation of the on-line post-maintenance testing of a DG in an extended CT, the commitments on pre-operational testing and analysis to demonstrate the capability of the Sharpe Station gensets to be a planned short-term substitute AC power source for a safety bus, and the licensee not proposing to use the crossties and cross-connecting of safety buses, the NRC staff concludes that it is safe for the licensee to operate WCGS using the proposed extended CT to maintain scheduled maintenance on DGs while the plant is in Modes 1 and 2.

3.4 Second CTs for Inoperable DGs and Offsite Circuits Because the licensee has proposed to extend the CTs for an inoperable DG from 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to 7 days, the licensee has also proposed to extend the second CTs in TS 3.8.1 for an inoperable DG, in TS 3.8.1 Required Actions A.3 and B.4, from 6 days to 10 days.

The proposed second CTs in the above TS 3.8.1, required actions are based on the algebraic sum of the extended CT for an inoperable DG and the CT for an inoperable offsite circuit (72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ) to determine the second CT for an inoperable DG. The use of the algebraic sum of a risk-informed CT (i.e., the risk-informed extended DG CT) and a deterministic CT (i.e., the CT for an inoperable offsite circuits) to determine the second CTs was first approved by the NRC staff in Amendment No. 151 for Grand Gulf Nuclear Station, Unit 1, issued July 16, 2002.

The CT is the amount of time allowed for completing an LCO required action and the "time zero" is normally the time of discovery of an abnormal situation, such as inoperable equipment or a variable not within limits, that requires entering an action condition for an LCO in the TSs, unless otherwise specified. If situations are discovered that require entry into more than one LCO action condition, the required actions for each condition must be performed within the associated CT. To avoid indefinitely entering and exiting multiple LCO conditions without restoring the system to meet the LCO, a second CT was established (See Example 1.3-3 in Section 1.3, "Completion Times," of the TSs) to prevent indefinite continued operation while not meeting the LCO. This second CT allows for an exception to the normal "time zero" for beginning a CT, in that the "time zero" for the second CT is the time the LCO was initially not met, instead of when the associated action condition was entered. Because this second CT is based on the combination of CTs for multiple condition entries, the second CT is deterministic in nature and was not reviewed by the NRC staff in terms of risk, which is consistent with previous NRC staff reviews related to proposed extensions of DG CTs.

The LCO 3.8.1, Required Actions A.3 and B.4 contain a second CT that is also proposed to be extended in the amendment. This CT establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during a single contiguous occurrence to meet the LCO. This CT limits the time allowed in a specific condition after the discovery of a failure to meet the LCO. The second CT of 6 days is extended to 10 days, consistent with the proposed DG CT and consistent with the intent of the TSs in that the proposed 10-day CT is a combination of Required Action A.3, "Restore Offsite Circuit to Operable Status," and B.4, "Restore DG to Operable Status," CTs and is not based on a risk- informed approach. Both conditions apply simultaneously, and the more restrictive CT must be met.

The second CT of 10 days (proposed to be changed from 6 days), establishes a limit on the maximum time allowed for any combination of an offsite circuit and DG being inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1. For example, if the CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for an inoperable offsite circuit is entered during the CT of 7 days (proposed to be changed from 3 days) for an inoperable DG that is returned to operable status, the LCO may already have not been met for up to the CT of 7 days for an inoperable DG. This could lead to a total of 10 days from the initial failure to meet the LCO due to an inoperable DG, to restore the offsite circuit to operable status. At this time, a DG could again become inoperable and an additional CT of 7 days for the inoperable DG could be allowed prior to complete restoration of the LCO. This could continue indefinitely, if not limited. The second CT of 10 days (proposed to be changed from 6 days) limits the time the plant can alternate between the conditions of an inoperable offsite circuit, an inoperable DG, and the combined inoperability of an offsite circuit and DG without meeting the LCO.

The WCGS TSs are based on the NRC-improved standard TSs (ISTS) for Westinghouse plants in NUREG-1431, "Standard Technical Specifications for Westinghouse Plants." No second CT was established in the STS, which pre-dates the ISTS in NUREG-1431, but the ISTS established a second CT to limit the time a plant can alternate between the condition of an inoperable DG, an inoperable offsite circuit, and some combination of an inoperable DG or offsite circuit meeting the LCO 3.8.1. The ISTS states that the second CT for an inoperable vital AC bus is the sum of the CTs for the multiple conditions.

Based on this, the NRC staff concludes that the algebraic sum of the extended CT for an inoperable DG and the CT for an inoperable offsite circuit to determine the second CT for an

inoperable DG is acceptable. The individual CTs would be approved separately, but the second CT would be the sum of the individual CTs.

3.5 Revised TS 3.8.1 Conditions In adding the proposed Condition C to LCO 3.8.1 for the case if the Sharpe Station is not available, as required by Required Action B.4.2.1, the licensee has also proposed to re-number the existing Conditions C through H to be the new Conditions D through I. The required actions for these conditions are also re-numbered. Because the proposed change is editorial and does not change any requirements in the TSs, and allows the new Condition C to be accommodated within the format of the TSs, the NRC staff concludes that the proposed change is acceptable.

In addition to re-numbering the existing Condition G, the licensee has also proposed to revise the list of conditions because of adding the new Condition C. The statement in existing Condition G is the following: "Required Action and associated Completion Time of Condition A, B, C, D, E, or F not met." For this condition, the plant would be required to shut down by being in Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in Mode 5 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The required actions and CTs for Condition G (and, therefore, the new Condition H) are not being changed by this amendment. The licensee has proposed to revise this list of conditions to be Condition A, C, D, E, F, or G and to add the following statement:

"OR Required Actions B.1, B.2, B.3.1, B.3.2, B.4.1, and B.4.2.2 and associated Completion Time not met." The reference to Condition B in the existing Condition G has been replaced by the reference to Required Actions B.1, B.2, B.3.1, B.3.2, B.4.1, and B.4.2.2. The only required action in Condition C that is not listed is Required Action B.4.2.1 on the Sharpe Station and the Condition C includes that Required Action B.4.2.1. Based on the proposed revision to the statement in existing Condition G, the NRC staff concludes that the proposed change merely accounts for re-numbering the conditions because of adding the new Condition C. Based on this, the NRC staff further concludes that the proposed change is editorial, does not change any requirements in the TSs, and allows the new Condition C to be accommodated within the format of the TSs. Thus, the NRC staff concludes that the proposed change is acceptable.

The proposed Condition H is the TS requirement to prevent the CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for the Sharpe Station not being available in proposed Condition C from extending the DG CT more than the 7 days that is approved in this amendment. The proposed Required Action B.4.2.2 requires that the DG in a planned maintenance be restored to operable status in 7 days and in 10 days from discovery of failure to meet the LCO. The second CT of 10 days from discovery to meet the LCO is addressed in Section 3.4 of this SE. If the DG is in the extended CT and the Sharpe Station is then found not available, Condition C would be entered. The licensee would then be in Required Action C.1 with a CT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore the Sharpe Station and Required B.4.2.2 with as CT of 7 days and 10 days from discovery of failure to meet the LCO for the DG. If the associated CT for either Condition C or required Action B.4.2.2 is not met, proposed Condition H requires that Required Actions H.1 and H.2 must be entered and the plant is required to shut down with the current required CTs of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to be in Mode 3 and 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months to be in Mode 5. Based on this, the NRC staff concludes that the proposed CT to restore the Sharpe Station can not extend the CT for the DG in a planned maintenance beyond the 7 days approved in this amendment.

3.6 Conclusion As discussed above, the NRC staff has evaluated the proposed changes to CTs for an inoperable DG in TSs 3.8.1. Based on the above evaluation, which involves risk and deterministic

considerations, the NRC staff concludes that it is safe to operate the plant using the proposed CTs for DGs and, therefore, the proposed CTs meet 10 CFR 50.36. Based on this conclusion, the NRC staff further concludes that the proposed amendment is acceptable.

In proposing new requirements in TS 3.8.1 on the Sharpe Station, the licensee is adding a new page to the TSs. To add the new page, the licensee is revising the TS page numbers for TSs 3.8.2 through 3.8.10, and these new pages are being issued in this amendment. Because only the page numbers are changing, TSs 3.8.3 through 3.8.8 and TS 3.8.10 are not being changed by this amendment. For TS 3.8.9, in addition to the page number changes, there are the changes discussed in Section 3.5 of this SE. In addition, page iii of the TS Table of Contents is also being changed to reflect the new page numbers for TSs 3.8.2 through 3.8.10.

As part of its review of the proposed amendment, the NRC staff also reviewed the changes to the TS 3.8.1 Bases that the licensee presented in Attachment IV to its supplemental letter dated November 18, 2005, for the amendment, which superceded the changes identified in its application for TS 3.8.1. The NRC staff did not have any disagreement with the identified changes in Attachment IV of the supplemental letter.

4.0 REGULATORY COMMITMENTS In Attachment VI to its application and its supplemental letter dated March 6, 2006, the licensee provided the following regulatory commitments for this amendment:

Stated in Application dated October 30, 2003:

1. The revision to the TS Bases will be implemented pursuant to the TS Bases Control Program, TS 5.5.14, upon implementation of this license amendment.

2. The licensee amendment will be implemented within 90 days from the date of issuance of the amendment.

3. The logic for breaker 69-4 will be modified to close with the line side energized and the 69 kV bus de-energized.

4. Additional compensatory measures and configuration risk management controls that will apply when entering the extended DG CT (greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and up to 7 days) include the following:

a. Perform work during favorable weather (September 6 through April 22).

b. Weather forecast checked for severe weather conditions.

c. Elective testing and maintenance activities are precluded in the switchyard that could cause a line outage or challenge offsite power availability.

d. Additional AC power Sharpe Station gensets available and performance acceptable.

e. Concurrent work on other key SSCs (i.e., the essential service water system, component cooling water system, motor/turbine auxiliary feedwater pumps, and residual heat removal system) is not planned.

For Commitment No. 1 above, the licensee stated that the identified revisions of the TS Bases based on the amendment will be incorporated in the TS Bases in accordance with TS 5.5.14,

"Technical Specification (TS) Bases Change Program," within 90 days of the amendment being approved. The identified revisions for TS 3.8.1 in the licensee's supplemental letter dated November 18, 2005, supercede the revisions for TS 3.8.1 in the licensee's application. The supplemental letter dated March 6, 2006, also included revisions for TS 3.8.1. There are no changes to the TS 3.8.9 Bases because the changes to TS 3.8.9 were withdrawn by the licensee in its supplemental letter dated March 6, 2006.

Commitment No. 2 is a license condition in that the amendment states it is effective as of its date of issuance, and shall be implemented within 90 days of the date of issuance.

For Commitment No. 3 above, as discussed in Section 3.4.2 of this SE, the logic for breaker 69-4 has to be modified to allow AC power from the Sharpe Station gensets to be passed through the WCGS switchyard via the 69 kV line to the safety busses. The licensee committed to complete this modification before the amendment is implemented. Therefore, before a DG could be taken out of service for on-line maintenance in an extended CT, the Sharpe Station gensets would be able to provide AC power in SBO to the safety busses. In a communication with NRC staff, the licensee stated that the modification has been completed.

For Commitment No. 4 above, the regulatory commitment follows the statements made by the licensee in the revised TS Bases provided for the proposed amendment in Attachment V to its application. These statements will be incorporated in the TS Bases as part of Commitment No. 1, above, before the implementation of the amendment is completed.

Stated in Supplemental letter dated March 6, 2006:

5. The licensee will coordinate with KEPCo to ensure a fuel oil vendor is available to provide fuel oil to the Sharpe Station on an as-needed basis prior to the first use of the extended 7-day CT for pre-planned DG maintenance activities.

6. Prior to the licensee entering TS 3.8.1 Required Action B.4.2.2 for voluntary planned maintenance activities and using the extended 7-day CT for pre-planned DG maintenance activities, administrative controls will be applied to ensure or require that:

a. Weather conditions are conducive to an extended DG CT. As stated in the first bullet in the fourth regulatory commitment listed in the licensee's application, the extended DG CT applies during the period of September 6 through April 22.

b. The offsite power supply and switchyard conditions are conducive to an extend DG CT, which includes ensuring that switchyard access is restricted and no elective maintenance within the switchyard is performed that would challenge the offsite power availability.

c. Prior to relying on the required Sharpe Station gensets, the gensets are started and proper operation is verified (i.e., the gensets reach rated speed and voltage). The Sharpe Station is not required to be operating during the allowed outage time of the DG maintenance activities; however, it shall be capable of providing greater than 8 MWs power to a dead bus (station blackout conditions) to power one ESF train. Within 8 months prior to each use of Required Action B.4.2.2, a load capability test/verification will be performed on the gensets. The load capability test/verification will consist of

either crediting a running of the gensets for load for commercial reasons for greater than one hour or tested by loading of the gensets for greater than one hour to a load greater than required to supply safety-related loads in the event of a station blackout.

d. No equipment or systems assumed to be available for supporting the extended DG CT are removed from service. The equipment or systems assumed to be available (including required support systems, i.e., associated room coolers, etc.) are as follows:

Auxiliary Feedwater System (3 trains), Component Cooling Water System (both trains and all four pumps), Essential Service Water System (both trains), and Emergency Core Cooling System (both trains).

7. Prior to the first use of the extended 7-day CT for pre-planned DG maintenance activities, inclusion of the risk impact of the Sharpe Station in the safety monitor will be accomplished.

This includes adding an activity to the Activity table of the safety monitor that will account for the impact of the plant configuration associated with crediting the Sharpe Station during use of the subject extended DG CT.

8. Prior to the first use of the extended 7-day CT for pre-planned DG maintenance activities, the licensee will perform a one-time load acceptance test of the Sharpe Station gensets. The one-time load acceptance test will be performed prior to the first use of the 7-day CT for pre-planned maintenance activities. The test will demonstrate the capability of the Sharpe Station to successfully start a large motor (a 1500 hp motor at a nearby gas pumping station) to simulate nuclear plant loads at WCGS. Additionally, a dynamic voltage flow analysis will be performed, using vendor provided test data for starting large motor loads, to further demonstrate from an analysis perspective that the Sharpe Station would be capable of starting and carrying designated loads, including maintaining adequate voltage and frequency such that performance of powered equipment would be acceptable. The licensee stated that this statement means that the analysis will demonstrate that the Sharpe Station gensets are capable of starting and carrying designated loads and that the voltage and frequency would be adequate to ensure no damage to equipment and degraded voltage and loss of voltage functions are not challenged.

Commitment Nos. 5, 6.c, 7, and 8 are new commitments made by the licensee. Commitment 7 was made a license condition in the licensee's supplemental letter dated April 14, 2005.

Commitment Nos. 6.a, 6.b, and 6.c are extensions of Commitments Nos. 4.a, 4.b, 4.c, and 4.d.

The licensee also proposed that the one-time load acceptance test and the periodic load capability test/verification (to be performed within 8 months prior to use of the extended DG CT) of the Sharpe Station in Commitment Nos. 8 and 6.c, respectively, will be requirements in that they are added to the operating license as license conditions.

Stated in Supplemental letter dated April 14, 2006:

9. Prior to the licensee's first use of the 7-day CT for preplanned maintenance, the licensee would ensure the 2002 WCGS PSA Model is using the NRC-approved WCAP-15603, Revision 1, RCP seal leakage model for Westinghouse plants, and verify that the use of the Sharpe Station for supporting the extended DG CT meets the risk acceptance guidelines in RGs 1.174 and 1.177.

This commitment is addressed in Section 3.3.1.1.1 of this SE on the RCP seal model. The licensee proposed this commitment as a license condition in the supplmental letter dated April 14, 2006.

The NRC staff finds that reasonable controls for the licensee's implementation and subsequent evaluation of any changes to the above regulatory commitments are provided by the licensee's administrative processes, including its commitment management program. The NRC staff has determined that Commitment Nos. 1, 3, and 4 do not warrant the creation of regulatory requirements which would require prior NRC approval of subsequent changes. The NRC staff has agreed that Nuclear Energy Institute (NEI) 99-04, "Guidelines for Managing NRC Commitment Changes," Revision 0, provides reasonable guidance for the control of regulatory commitments made to the NRC staff. See Regulatory Issue Summary 2000-17, "Managing Regulatory Commitments Made by Power Reactor Licensees to the NRC Staff," dated September 21, 2000.

The commitments will be controlled in accordance with the licensee's commitment management program in accordance with NEI 99-04. Any change to the regulatory commitments is subject to licensee management approval and subject to the procedural controls established at the plant for commitment management in accordance with NEI 99-04, which include notification of the NRC.

Also, the NRC staff may choose to verify the implementation and maintenance of these commitments in a future inspection or audit. Based on this, the NRC staff concludes that the first and third through eighth regulatory commitments listed above are acceptable.

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Kansas State official was notified of the proposed issuance of the amendment. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration and there has been no public comment on such finding (69 FR 700, published on January 6, 2004). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (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.

Principal Contributors: Jack Donohew

Stephen Dinsmore Thomas Koshy Date: April 26, 2006

Wolf Creek Generating Station cc:

Jay Silberg, Esq. Vice President Operations/Plant Manager Shaw Pittman, LLP Wolf Creek Nuclear Operating Corporation 2300 N Street, NW P.O. Box 411 Washington, D.C. 20037 Burlington, KS 66839 Regional Administrator, Region IV Supervisor Licensing U.S. Nuclear Regulatory Commission Wolf Creek Nuclear Operating Corporation 611 Ryan Plaza Drive, Suite 400 P.O. Box 411 Arlington, TX 76011 Burlington, KS 66839 Senior Resident Inspector U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Resident Inspectors Office/Callaway Plant P.O. Box 311 8201 NRC Road Burlington, KS 66839 Steedman, MO 65077-1032 Chief Engineer, Utilities Division Kansas Corporation Commission 1500 SW Arrowhead Road Topeka, KS 66604-4027 Office of the Governor State of Kansas Topeka, KS 66612 Attorney General 120 S.W. 10th Avenue, 2nd Floor Topeka, KS 66612-1597 County Clerk Coffey County Courthouse 110 South 6th Street Burlington, KS 66839 Chief, Radiation and Asbestos Control Section Kansas Department of Health and Environment Bureau of Air and Radiation 1000 SW Jackson, Suite 310 Topeka, KS 66612-1366 November 2005

v t e Letter Sequence Approval
TAC:MC1257, (Approved, Closed)
Initiation Request Acceptance Administration Questions Answers Results Approval Other:
MONTHYEAR2005-11-18 [Table View]

ML053490174

Text

SUBJECT:

Dear Mr. Muench:

Enclosures:

SUBJECT:

Dear Mr. Muench:

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

5.0 STATE CONSULTATION

6.0 ENVIRONMENTAL CONSIDERATION

7.0 CONCLUSION

Navigation menu

Search