Text

Common Stars License Amendment Regarding Implementation of WCAP-14333 and WCAP-15379, RTS and ESFAS Test Times, Completion Times, and Surveillance Test Intervals
	ML040080026
Person / Time
Site:	Callaway
Issue date:	12/17/2003
From:	Keith Young; AmerenUE
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	ULNRC-04929, WCAP-14333, WCAP-15376
	Download: ML040080026 (185)
	v • d • e

AmerenUE Callaway lant PO Box 620 Fulton, MO 65251 December 17, 2003 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Mail Stop P1-137 Washington, DC 20555-0001 WAmerel Uf Ladies and Gentlemen:

ULNRC-04929 DOCKET NUMBER 50-483 CALLAWAY PLANT UNION ELECTRIC COMPANY COMMON STARS LICENSE AMENDMENT IMPLEMENTATION OF WCAP-14333 AND WA'CAP-15376 RTS AND ESFAS TEST TIMES, COMPLETION TIMES, AND SURVEILLANCE TEST INTERVALS AmerenUE herewith transmits an application for amendment to Facility Operating License No. NPF-30 for the Callaway Plant.

The proposed amendment would revise Technical Specification (TS) 3.3.1, Reactor Trip System (RTS) Instrumentation, TS 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation, and TS 3.3.9, Boron Dilution Mitigation System (BDMS) to adopt Completion Time, test bypass time, and Surveillance Frequency changes approved by NRC in WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998 and WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003. As discussed in Attachment 1, this amendment application is consistent with the following NRC-approved travelers:

Industry/Technical Specification Task Force (TSTF) Standard TS (STS) Change Traveler 411, Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376)"; and Industry/TSTF STS Change Traveler 418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)."

kpI a subsidiary of Ameren Corporation

ULNRC-04929 December 17, 2003 Page 2 AmerenUE is submitting this license amendment application in conjunction with an industry consortium of six plants as a result of a mutual agreement known as Strategic Teaming and Resource Sharing (STARS). The STARS group consists of the six plants operated by TXU Energy, AmerenUE, Wolf Creek Nuclear Operating Corporation, Pacific Gas and Electric Company, STP Nuclear Operating Company, and Arizona Public Service Company. AmerenUE's Callaway Plant is the lead plant for the proposed license amendment and other members of the STARS group can also be expected to submit a license amendment request similar to this one. The other license amendment requests will be submitted on a parallel basis within a short period of time of each other, with plant-specific information presented within brackets (i.e.,

within [ ] ) in Attachment 1 (other than TS LCO numbers which vary between Standard Technical Specifications of NUREG-0452 and NUREG-1431). All other Attachments are plant-specific in nature.

Attachments 1 through 6 provide the Evaluation, Markup of Technical Specifications, Retyped Technical Specifications, Proposed Technical Specification Bases Changes, Summary of Regulatory Commitments, and Topical Report Applicability Determination, respectively, in support of this amendment request. is provided for information only. Final Technical Specification Bases changes will be implemented under our program for updates per ITS 5.5.14, "Technical Specification Bases Control Program," at the time this amendment is implemented. Commitments based on the RG 1.177 Tier 2 evaluation are contained in Attachment 5.

Westinghouse has determined that information contained in Attachment 6 is proprietary, and is thereby supported by an affidavit signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR 2.790.

Accordingly, it is respectfully requested that the information that is proprietary to Westinghouse be withheld from public disclosure in accordance with 10 CFR 2.790.

This letter transmits proprietary and non-proprietary copies of Attachment 6.

Also enclosed are Westinghouse authorization letter CAW-03-1748, its accompanying affidavit, Proprietary Information Notice, and Copyright Notice.

Correspondence with respect to the copyright or proprietary aspects of the items listed above or the supporting Westinghouse affidavit should reference CAW-03-1748 and should be addressed to J. S. Galembush, Acting Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.

ULNRC-04929 December 17, 2003 Page 3 It has been determined that this amendment application does not involve a significant hazard consideration as determined per 10 CFR 50.92. Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of this amendment. NRC approval of this amendment application is requested by September 1, 2004. The amendment will be implemented within 90 days after NRC approval. In accordance with 10 CFR 50.91, a copy of this amendment application is being provided to the designated Missouri State official.

If you have any questions on this amendment application, please contact us.

Very truly yours, Keith D. Yo Manager-Regulatory Affairs GGY/mlo Attachments:

I Evaluation 2

Markup of Technical Specifications 3

Retyped Technical Specifications 4

Proposed Technical Specification Bases Changes (for information only) 5 Summary of Regulatory Commitments 6A -

Topical Report Applicability Determination (Proprietary) 6B -

Topical Report Applicability Determination (Non-Proprietary) 6C -

Topical Report Applicability Determination - Proprietary Affidavit

STATE OF MISSOURI

)

Ss CALLAWAY COUNTY Keith D. Young of lawful age, being first duly sworn upon oath says that he is Manager - Regulatory Affairs, for Union Electric Company; that he has read the foregoing document and knows the content thereof; that he has executed the same for and on behalf of said company with full power and authority to do so; and that the facts therein stated are true and correct to the best of his knowledge, information and belief.

By

&tv dJAGLO Keith D. YoW Manager, Regulatory Affairs SUBSCRIBED and sworn to before me this day of ii ec-e r-A -e--

. 2003.

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ULNRC-04929 December 17, 2003 Page 4 cc:

U. S. Nuclear Regulatory Commission (Original and I copy)

Attn: Document Control Desk Mail Stop P1-137 Washington, DC 20555-0001 Mr. Bruce S. Mallet Regional Administrator U.S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-4005 Senior Resident Inspector Callaway Resident Office U.S. Nuclear Regulatory Commission 8201 NRC Road Steedman, MO 65077 Mr. Jack N. Donohew (2 copies)

Licensing Project Manager, Callaway Plant Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop 7EI Washington, DC 20555-2738 Manager, Electric Department Missouri Public Service Commission PO Box 360 Jefferson City, MO 65102 Page 1 of 30 EVALUATION

1. DESCRIPTION

2. PROPOSED CHANGE

3. BACKGROUND

4. TECHNICAL ANALYSIS

5. REGULATORY ANALYSIS 5.1 NO SIGNIFICANT HAZARDS CONSIDERATION 5.2 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA

6. ENVIRONMENTAL CONSIDERATION

7. REFERENCES Page 2 of 30 EVALUATION

1.0 DESCRIPTION

The proposed amendment would revise Technical Specification (TS) 3.3.1, Reactor Trip System (RTS) Instrumentation, TS 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation, [and TS 3.3.9, Boron Dilution Mitigation System (BDMS)] to adopt the Completion Time, test bypass time, and Surveillance Frequency changes approved by NRC in WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998 (Reference 1) and WCAP-1 5376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003 (Reference 2). This amendment application is consistent with the following NRC-approved travelers: Industry/Technical Specification Task Force (TSTF) Standard TS (STS) Change Traveler 411, Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376)"; and Industry/TSTF STS Change Traveler 418, Revision 2, RPS and ESFAS Test Times and Completion Times (WCAP-14333)," References 3 and 4, respectively. All references cited in this Evaluation are listed in Section 7.0.

2.0 PROPOSED CHANGE

The following categories of changes are proposed for Technical Specifications 3.3.1, 3.3.2, [and 3.3.9]:

a)

The allowed Completion Time to restore an inoperable RTS or ESFAS analog channel, before it must be placed in the tripped condition

[bypassed condition for Containment Pressure High - 3], is increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ; b)

The allowed time for an inoperable RTS or ESFAS analog channel to be bypassed [ ] for testing other analog channels is increased from 4 to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; c)

The allowed Completion Time to restore an inoperable train of Solid State Protection System (SSPS) logic (TS 3.3.1 and TS 3.3.2) or actuation Page 3 of 30 relays (TS 3.3.2), before the plant must be shut down, is increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; d)

The allowed time for one reactor trip breaker (RTB) train to be bypassed for [RTB] surveillance testing is increased from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; e)

The allowed Completion Time to restore an inoperable RTB train, before the plant must be shut down, is increased from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; f)

The surveillance test interval for the RTB TRIP ACTUATING DEVICE OPERATIONAL TEST (TADOT) is increased from 31 days on a STAGGERED TEST BASIS to 62 days on a STAGGERED TEST BASIS; g)

The surveillance test interval for the SSPS ACTUATION LOGIC TEST and MASTER RELAY TEST is increased from 31 days on a STAGGERED TEST BASIS to 92 days on a STAGGERED TEST BASIS; h)

The CHANNEL OPERATIONAL TEST (COT) surveillance test interval in TS 3.3.1, TS 3.3.2, [and TS 3.3.9] is increased from 92 days to 184 days; and

[i)

In a change unrelated to these two topical reports, the Note above Callaway SR 3.3.2.6 and corresponding Bases are revised to reflect that slave relay K750 is not tested on a 92-day Frequency. Slave relay K750 is tested on an 18-month Frequency under SR 3.3.2.14 which was included in Reference 5 and approved by NRC in Reference 6.] contains the Technical Specification mark-ups for the above changes. The following changes are included in Attachment 2:

1)

Modified bypass testing Note and extended Completion Times for TS 3.3.1 Condition D Power Range Neutron Flux - High {RTS Function 2.a};

2)

Modified bypass testing Note and extended Completion Times for TS 3.3.1 Required Actions E.1 and E.2 Power Range Neutron Flux - Low {RTS Function 2.b}, Power Range Neutron Flux - [High Positive Rate {RTS Function 3}], Overtemperature AT

{RTS Function 6}, Overpower AT {RTS Function 7}, Pressurizer Pressure -

High {RTS Function 8.b}, and Steam Generator Water Level Low-Low Page 4 of 30

[Adverse and Normal Containment Environment {RTS Functions 14.a and 14.b}];

3)

Modified bypass testing Note and extended Completion Times for TS 3.3.1 Required Actions M.1 and M.2 Pressurizer Pressure - Low {RTS Function 8.a}, Pressurizer Water Level -

High {RTS Function 91, Reactor Coolant Flow - Low {RTS Function 10},

Undervoltage RCPs {RTS Function 121, and Underfrequency RCPs {RTS Function 13};

4)

Modified bypass testing Note and extended Completion Times for TS 3.3.1 Required Actions 0.1 and 0.2 Turbine Trip Low Fluid Oil Pressure {RTS Function 16.a};

5)

Extended Completion Times for TS 3.3.1 Required Actions P.1 and P.2 Turbine Trip Turbine Stop Valve Closure {RTS Function 16.b};

6)

Extended Completion Times for TS 3.3.1 Required Actions Q.1 and Q.2 Safety Injection Input from ESFAS {RTS Function 17} and Automatic Trip Logic {RTS Function 21);

7)

Modified bypass testing Note 1, [deleted bypass Notes 2 and 3], and extended Completion Times for TS 3.3.1 Required Actions R.1 and R.2

{RTS Function 19};

[8)

Extended Completion Times for TS 3.3.1 Required Actions W.1 and W.2 Steam Generator Water Level Low-Low Vessel AT Power-1 and Power-2

{RTS Functions 14.c.(1) and 14.c.(2)};

9)

Extended Completion Times for TS 3.3.1 Required Actions X.1 and X.2 Steam Generator Water Level Low-Low Containment Pressure -

Environmental Allowance Modifier {RTS Function 14.d);]

10)

Extended SR 3.3.1.4, RTB TADOT;

11)

Extended SR 3.3.1.5, SSPS ACTUATION LOGIC TEST; Page 5 of 30

12)

Extended SR 3.3.1.7 and SR 3.3.1.8, RTS instrumentation COTs;

13)

Extended Completion Times for TS 3.3.2 Required Actions C.2, C.3.1, and C.3.2 Automatic Actuation Logic and Actuation Relays (SSPS) for:

Safety Injection {ESFAS Function 1.b), Containment Spray {ESFAS Function 2.b}, Containment Isolation - Phase A Isolation {ESFAS Function 3.a.(2)1, Containment Isolation - Phase B Isolation {ESFAS Function 3.b.(2)1, and Automatic Switchover to Containment Sump {ESFAS Function 7.al;

14)

Modified bypass testing Note and extended Completion Times for TS 3.3.2 Required Actions D.1, D.2.1, and D.2.2 Safety Injection on Containment Pressure - High 1 {ESFAS Function.c},

Pressurizer Pressure - Low {ESFAS Function 1.dl, and Steam Line Pressure - Low {ESFAS Function 1.e}; Steam Line Isolation on Containment Pressure - High 2 {ESFAS Function 4.[d]}, Steam Line Pressure - Low {ESFAS Function 4.[e].(1), and Steam Line Pressure Negative Rate - High {ESFAS Function 4.[e].(2); Steam Generator Water Level Low-Low [Adverse and Normal Containment Environment] for

[Feedwater Isolation and] Auxiliary Feedwater {ESFAS Functions [5.e.(1),

5.e.(2), 6.(d).1, and 6.d.(2)]}, [Automatic Pressurizer PORV Actuation on Pressurizer Pressure - High {ESFAS Function 9.b}];

15)

Modified bypass testing Note and extended Completion Times for TS 3.3.2 Required Actions E.1, E.2.1, and E.2.2 Containment Pressure - High 3 for Containment Spray {ESFAS Function 2.c} and for Containment Isolation - Phase B Isolation {ESFAS Function 3.b.(3));

16)

Extended Completion Times for TS 3.3.2 Required Actions G.1, G.2.1, and G.2.2 Automatic Actuation Logic and Actuation Relays (SSPS) for Steam Line Isolation {ESFAS Function 4.b}, [Turbine Trip and Feedwater Isolation

{ESFAS Function 5.b}], and Auxiliary Feedwater {ESFAS Function 6.b);

[1 Page 6 of 30

[17)

Added new Condition S to retain the current Required Actions and Completion Times and revised SR 3.3.2.3 and its Note to apply to the Automatic Actuation Logic and Actuation Relays (MSFIS) for Steam Line Isolation {ESFAS Function 4.c} and for Turbine Trip and Feedwater Isolation {ESFAS Function 5.b} since the Main Steam and Feedwater Isolation System (MSFIS) logic function is not covered by WCAP-14333-P-A or WCAP-1 5376-P-A];

18)

Modified bypass testing Note and extended Completion Times for TS 3.3.2 Required Action 1.1 and 1.2 Turbine Trip and Feedwater Isolation on SG Water Level - High High

{ESFAS Function 5.[c]};

[19)

Modified bypass testing Note, deleted Required Action K.1, and re-numbered remaining Required Actions for Condition K]

Automatic Switchover to Containment Sump on Refueling Water Storage Tank Level Low - Low Coincident with Safety Injection {ESFAS Function 7.b);

[20)

Extended Completion Times for TS 3.3.2 Required Actions M.1 and M.2 Steam Generator Water Level Low-Low Vessel AT Power-1 and Power-2 for Feedwater Isolation {ESFAS Functions 5.e.(3).(a) and 5.e.(3).(b)} and for Auxiliary Feedwater {ESFAS Functions 6.d.(3).(a) and 6.d.(3).(b)};

21)

Extended Completion Times for TS 3.3.2 Required Actions N.1, N.2.1, N.2.2 Steam Generator Water Level Low-Low Containment Pressure -

Environmental Allowance Modifier for Feedwater Isolation {ESFAS Function 5.e.(4)} and for Auxiliary Feedwater {ESFAS Function 6.d.(4)};]

22)

Extended SR 3.3.2.2 and SR 3.3.2.4, SSPS ACTUATION LOGIC TEST and MASTER RELAY TEST [and revised the SR 3.3.2.3 Note];

23)

Extended SR 3.3.2.5, ESFAS instrumentation COTs;

[24)

Revised Note for SR 3.3.2.6, SLAVE RELAY TEST; and

25)

Extended SR 3.3.9.3, BDMS COT.

Page 7 of 30 In addition, an editorial correction was made in the Callaway Technical Specifications regarding the "AND" logic connector between Required Actions 0.1 and 0.2 in TS 3.3.2 Condition 0 for ESFAS Function 6.h, Auxiliary Feedwater Pump Suction Transfer on Suction Pressure - Low. The "AND" logic connector should be left justified.]

The Corresponding TS Bases are also revised in Attachment 4 to be consistent with the above changes.

3.0 BACKGROUND

Over the past several years the Westinghouse Owners Group (WOG) completed a series of topical reports that document the relaxation of RTS and ESFAS test times, Completion Times (CTs), and surveillance test intervals (STIs) for the protection system instrumentation. The relaxations were justified by an analysis of the protection system reliability and the impact of that reliability on the overall plant risk. The original study was identified by the acronym TOP (taken from Technical Specification Optimization Program) as documented in the WCAP-10271-P-A series of reports. Those changes were implemented at [Callaway Plant via OL Amendment 17 for the RTS and OL Amendment 64 for the ESFAS, References 7 and 8, respectively. When reviewing risk metric results, Callaway's current licensing basis is that of a 'TOP" plant.]

Fault tree models of the protection system instrumentation were used to calculate the unavailability sensitivity to test and maintenance time allowances and frequencies. The changes in RTS and ESFAS unavailability were then used in a risk model to predict changes in risk as the test and maintenance time allowances and frequencies were relaxed. Differences in analysis methods from the TOPS WCAP-10271-P-A (hereafter referred to as WCAP-10271) series of reports are discussed in Section 7.1 of WCAP-14333-P-A Revision 1 and in Section 8.3.5 of WCAP-15376-P-A Revision 1.

The approach used in WCAP-14333-P-A Revision 1 (hereafter referred to as WCAP-14333) and WCAP-1 5376-P-A Revision 1 (hereafter referred to as WCAP-1 5376) is consistent with the approach established in the TOP program.

This includes the fault tree models, signals, component reliability database, and most of the test and maintenance assumptions. The methodology used in the WCAP-1 0271 studies was applied to a representative set of RTS and ESFAS functions using the Vogtle Plant PRA model and revised unavailability data. The work documented in WCAP-14333 uses a different common cause failure modeling approach for analog channels and includes more realistic assumptions Page 8 of 30 related to the component unavailability due to maintenance activities based on a survey of WOG plants. Operator actions to either manually trip the reactor or initiate safety injection are also modeled in WCAP-14333. In addition, credit for auxiliary feedwater pump start from the ATWS mitigating system actuation circuitry (AMSAC) was taken. More discussion of these differences is contained in Sections 7 and 8 of WCAP-14333. The relaxations that are justified in WCAP-14333 are summarized below:

Summary of WCAP-14333 RTS and ESFAS Completion Time and Bypass Test Time Changes - Solid State Protection System Component Completion Time Bypass Test Time Analog 6+6 hours to 72+6 hours 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels Logic train 6+6 hours to 24+6 hours no relaxation*

Actuation relays 6+6 hours to 24+6 hours no relaxation*

no relaxation beyond TOP (WCAP-10271 and its supplements)

WCAP-14333 was submitted for NRC review with WOG letter OG-95-51 dated June 20, 1995. The NRC issued a Safety Evaluation on July 15,1998 approving WCAP-14333. These improvements will allow additional time to perform maintenance and test activities, enhance safety, provide additional operational flexibility, and reduce the potential for forced outages related to compliance with the RTS and ESFAS instrumentation Technical Specifications. Industry information has shown that a significant number of trips that have occurred are related to instrumentation test and maintenance activities, indicating that these activities should be completed with caution and sufficient time should be available to complete these activities in an orderly and effective manner.

Southern Nuclear Operating Company submitted a License Amendment Request on October 13,1999 for the Vogtle Units 1 and 2 to adopt the relaxations that were generically approved in WCAP-14333. As a result of the NRC review of this application, incremental conditional large early release probability (ICLERP) values were developed generically for all WOG plants. See Reference 10 for the Vogtle amendment correspondence. Amendments 116 and 94 were issued for Vogtle approving the changes proposed in WCAP-14333.

WOG letter OG-00-1 12, dated November 8, 2000, transmitted WCAP-1 5376, Revision 0 to the NRC for review and approval. WCAP-15376 expanded upon the groundwork laid by WCAP-14333, but used updated component failure Page 9 of 30 probability data (WCAP-15376 Section 8.2) and made some changes to the fault tree models (WCAP-15376 Section 8.3). Using these modifications, the changes previously approved in WCAP-14333 were quantified as the base case for WCAP-15376. Section 8.4 of WCAP-1 5376 provides the risk metrics for this change and demonstrates that the acceptance criteria of RG 1.174 and RG 1.177 are satisfied.

WCAP-1 5376 provides the technical justification for the following RTS Instrumentation (TS 3.3.1), ESFAS Instrumentation (TS 3.3.2), [and BDMS (TS 3.3.9)] Technical Specification changes:

Summary of WCAP-15376 RTS and ESFAS STI and CT Changes -

Solid State Protection System Component Surveillance Test Completion Times Intervals and Bypass Times Logic Train 2 months to 6 months No changes Master Relays 2 months to 6 months No changes Analog Channels 3 months to 6 months No changes Reactor Trip Breakers 2 months to 4 months AOT: 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Bypass Time: 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months The NRC approved WCAP-1 5376 by letter dated December 20, 2002.

The AMSAC system is included in [Callaway's Maintenance Rule Program as a non-risk significant system with an assigned reliability performance criterion of no more than two maintenance preventable functional failures per operating cycle.

AMSAC is not risk-significant under the Callaway Maintenance Rule Program based primarily on its low risk achievement worth (1.07) and low risk reduction worth (1.001), which are well below the NUMARC 93-01 risk significance thresholds of 2.0 and 1.005, respectively. In the Callaway Maintenance Rule Program, structures, systems, and components (SSCs) that are not risk significant, such as AMSAC, are monitored at the plant level and do not have SSC-specific performance criteria such as unavailability hours per cycle.

AMSAC is calibrated every 18 months. More discussion on Callaway's AMSAC design may be found in FSAR Section 7.7.1.11.]

Page 10 of 30

4.0 TECHNICAL ANALYSIS

A survey was provided to all WOG members to determine their needs with respect to instrumentation test times, maintenance times, and maintenance frequencies, in addition to information regarding plant operation such as reactor trip and spurious safety injection events. From this information the Technical Specification changes that were evaluated were identified. The probabilistic risk analysis, benefits of the program and conclusions, and the relationship of the Technical Specification changes to the analyses are discussed in WCAP-14333 and WCAP-1 5376.

In order to model the Completion Times in the fault trees to determine the impact of the changes on signal unavailabilities, several parameters were specified for component test and maintenance unavailabilities. These are the test frequencies and durations discussed in Section 5.1 of WCAP-14333, the maintenance frequencies and durations discussed in Section 5.2 of WCAP-14333, and the test and maintenance activities discussed in Section 7.2 of WCAP-15376.

The changes being considered in this analysis were evaluated consistent with the three-tiered approach currently defined in Regulatory Guide 1.177. The first tier addresses PRA insights and includes the risk analyses and sensitivity analyses to support the completion time and bypass test time changes. The second tier addresses avoidance of risk-significant plant configurations. The third tier addresses risk-informed plant configuration control and management.

Tier 1, PRA Capability and Insights WCAP-14333 WCAP-14333 originally provided only the impact of the requested changes on core damage frequency (ACDF) for two-out-of-four (2/4) and two-out-of-three (2/3) actuation logic. In response to an NRC request for additional information (RAI) letter, RAI Questions 11 and 13 in WOG letter OG-96-1 10 (Reference 9),

the WOG provided the impact of the requested changes on incremental conditional core damage probability (ICCDP) for various components in maintenance and the change in large early release frequency (ALERF) for 2/4 and 2/3 actuation logic. Also, in response to an NRC RAI during the review of Southern Nuclear's amendment request implementing these changes for the

Page 11 of 30 Vogtle Units 1 and 2 (Reference 10), incremental conditional large early release probabilities (ICLERPs) for various components in maintenance were provided.

The impact of the proposed changes on CDF and LERF are provided in TSTF-418, Revision 2, Table 1.3 (which presents the same information as that contained in Table 8.4 of WCAP-14333) and Table 1.4 (which presents the same information as that contained in the response to RAI Question'3 in OG-96-1 10),

respectively. The CDF and LERF values are provided for pre-TOP, TOP, and the WCAP-14333 proposed changes. The ACDF and ALERF values are also provided referenced to pre-TOP and TOP conditions. The results of a sensitivity analysis are also provided that credits a 0.5/year reduction in reactor trip frequency due to fewer analog channel tests (trip reduction originally postulated for the WCAP-1 0271 channel operational test interval increase from monthly to quarterly). The ACDF and ALERF values are provided for both 2/4 and 2/3 logic.

The ICCDP and ICLERP values are provided on Table 1.5 of TSTF-418, Revision 2 (from RAI Question 11 in OG-96-1 10 and from Reference 10). The ICCDP and ICLERP values are provided only for 2/3 logic, but the results envelop the 2/4 logic.

WCAP-1 5376 Risk analysis results for WCAP-1 5376 are discussed in Section 8.4 of that topical report. Comparisons are presented in Tables 8.29 (ACDF) and 8.32 (ALERF) to a base case which represents the changes previously approved under WCAP-14333. In response to an NRC request for additional information letter, RAI Questions 4 and 11 in WOG letter OG-02-002 (Reference 11), the WOG provided the impact of the requested Completion Time change (24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time plus 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to reach MODE 3, for a total of 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ) on ICCDP and ICLERP for a reactor trip breaker (RTB) in preventive maintenance (PM) or in corrective maintenance (CM), with the associated logic train inoperable, for the bounding 2/3 logic. Since these incremental risk metrics are met for a 30-hour maintenance time, they will also be met for a 4-hour bypass test time.

Page 12 of 30 Combined Risk Metric Results Risk Metric Acceptance Change from WCAP-10271 Change from WCAP-Criterion to WCAP-14333 14333 to WCAP-1 5376 ACDF

< 1 E-06 2/4 logic 2/3 logic 2/4 logic 2/3 logic per year 3.5E-07 6.1E-07 8.OE-07 8.5E-07 ICCDP

< 5E-07 Ranges from 4. E-07 (logic RTB in PM - 3.20E-07 train in maintenance) to RTB in CM - 3.22E-07 5.5E-10 (SG level channel in test)

ALERF

< 1 E-07 2/4 logic 2/3 logic 2/4 logic 2/3 logic per year 2.OE-08 2.2E-08 3.09E-08 5.68E-08 ICLERP

< 5E-08 Ranges from 3.OE-08 (logic RTB in PM - 2.41 E-08 train in maintenance) to RTB in CM - 2.42E-08 1.1 E-11 (SG level channel in test)

The ICCDP and ICLERP values are situational in nature, depending on the particular component under test or maintenance. The acceptance criteria for these incremental risk metrics are satisfied. The ACDF and ALERF values are cumulative from the current licensing basis (WCAP-1 0271) to the proposed state (WCAP-15376). The ALERF acceptance criterion is satisfied. From the above table, the ACDF acceptance criterion is slightly exceeded. To address this, Section 8.4.4 and Table 8.33 of WCAP-1 5376 discuss the cumulative ACDF from pre-TOP to WCAP-1 5376 conditions using the sensitivity analysis values from Table 8.4 of WCAP-14333 for 2/4 logic and 2/3 logic combined with the ACDF values from Table 8.29 of WCAP-1 5376 for 2/4 and 2/3 logic. The cumulative ACDF for the 2/4 logic in Table 8.33 of WCAP-1 5376 is 5.7E-07/year meeting the ACDF acceptance criterion. The cumulative ACDF for the 2/3 logic in Table 8.33 of WCAP-1 5376 is 1.1 E-06/year slightly exceeding the ACDF acceptance criterion. However, that ACDF of 1.1E-06/year includes the cumulative impact of changing from the pre-TOP to WCAP-15376 conditions. Pre-TOP conditions are given in Table 1.1 of WCAP-15376. [Since Callaway is changing only from the TOP to WCAP-15376 conditions, the ACDF acceptance criterion is satisfied since we are currently licensed with quarterly COTs and 6-hour Completion Times, i.e., we are requesting less of a delta than the pre-TOP to WCAP-15376 change.] Another supplemental consideration supporting compliance with the ACDF acceptance criterion is the shutdown risk avoided with extended Completion Times discussed in Section 8.4 of WCAP-14333 and Section 8.7 of WCAP-1 5376.

Page 13 of 30 Tier 2, Avoidance of Risk-Significant Plant Configurations Tier 2 requires an examination of the need to impose additional restrictions when operating under the proposed Completion Times in order to avoid risk-significant equipment outage configurations. Not surprisingly, the resulting Tier 2 restrictions to be imposed for the two topical reports are very similar.

WCAP-1 4333 Consistent with the guidance in Regulatory Position C.2.3 in RG 1.177, Westinghouse performed an evaluation of equipment according to its contribution to plant risk while the equipment covered by the proposed Completion Time changes is out of service for test or maintenance. This evaluation was documented in the response to RAI Question 18 in Westinghouse letter OG 110 (Reference 9). Westinghouse performed an importance analysis for 25 top events in the event trees for each of the test or maintenance configurations associated with the proposed TS changes. This analysis determined the system importances for plant configurations with no ongoing test and maintenance activities (all components available) and for plant configurations with ongoing test or maintenance activities individually on the analog channels, logic trains, master relays, and slave relays. With test or maintenance activities in progress, it is assumed that the corresponding component or train will be unavailable. The system importances for these configurations are provided in Table Q18.1 of the response to RAI Question 18. The importances were compared between the cases with individual components unavailable and all components available.

For the cases of the analog channels, master relays, and slave relays, the importance rankings among the systems involved did not change. For the case of an SSPS logic train in maintenance, several systems had a relatively significant increase in their importance ranking. Those systems were auxiliary feedwater (AFW), reactor trip, high pressure injection, low pressure injection, and containment cooling.

In addition, as discussed previously, the response to RAI Question 11 in Reference 9 documented ICCDP values for the various test and maintenance configurations that the plant may enter for the subject Completion Time extensions. This information is provided in Table Q1 1.1 of the response to RAI Question 11. The same conclusion is drawn from the information presented on Table Q 11.1, i.e., the only configuration that significantly impacts core damage frequency is that with a logic train inoperable.

Page 14 of 30 Based on the information provided in RAI response Tables Q1.1 and Q18.1, it is concluded that the only plant configuration with an appreciable impact on CDF or a significant impact on the relative importance of other systems is the configuration with one logic train inoperable. Therefore, the Tier 2 limitations are appropriate only when a logic train is inoperable. There are no Tier 2 limitations when a slave relay, master relay, or analog channel is inoperable.

Consistent with the WCAP-14333 SE requirement to include Tier 2 insights into the decision-making process before taking equipment out of service, restrictions on concurrent removal of certain equipment when a logic train is inoperable for maintenance will be included (note that these restrictions do not apply when a logic train is being tested under the 4-hour bypass Note of TS 3.3.1 Condition Q, TS 3.3.2 Condition C, or TS 3.3.2 Condition G). Entry into these Conditions is not a typical, pre-planned evolution during power operation, other than for surveillance testing. Since these Conditions are typically entered due to equipment failure, it follows that some of the following Tier 2 restrictions may not be met at the time of Condition entry. If this situation were to occur during the extended 24-hour Completion Time, the Tier 3 Configuration Risk Management Program discussed below will assess the emergent condition and direct activities to restore the inoperable logic train and exit the Condition or fully implement the Tier 2 restrictions or perform a plant shutdown, as appropriate from a risk management perspective. The following restrictions will be put into place (see also Attachment 5):

To preserve ATWS mitigation capability, activities that degrade the availability of the auxiliary feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a logic train is inoperable for maintenance.

To preserve LOCA mitigation capability, one complete ECCS train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

To preserve reactor trip and safeguards actuation capability, activities that cause master relays or slave relays in the available train to be unavailable and activities that cause analog channels to be unavailable should not be scheduled when a logic train is inoperable for maintenance.

Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., essential service water and component cooling water) that support the systems or functions listed in the first three bullets should not be scheduled when a logic train is inoperable for maintenance. That is,

Page 15 of 30 one complete train of a function that supports a complete train of a function noted above must be available.

Note that the containment cooling system was shown to have a relatively significant increase in importance ranking in Table Q18.1 when a logic train is inoperable. However, in the [Callaway] PRA, containment cooling has no bearing whatsoever on core damage frequency. As discussed in Enclosure 6 of the October 13, 1999 Vogtle amendment request (Reference 10), increasing the availability of the containment cooling system will not offset or counter the inoperable logic train and no Tier 2 limitations are appropriate for this system.

WCAP-1 5376 Recommended Tier 2 restrictions for WCAP-1 5376 are provided in Section 8.5 of that topical report when a RTB train is inoperable for maintenance (note that these restrictions do not apply when a RTB train is being tested under the 4-hour bypass Note for TS 3.3.1 Condition R). Entry into this Condition is not a typical, pre-planned evolution during power operation, other than for surveillance testing.

Since this Condition is typically entered due to equipment failure, it follows that some of the following Tier 2 restrictions may not be met at the time of Condition entry. If this situation were to occur during the extended 24-hour Completion Time, the Tier 3 Configuration Risk Management Program discussed below will assess the emergent condition and direct activities to restore the inoperable RTB train and exit the Condition or fully implement the Tier 2 restrictions or perform a plant shutdown, as appropriate from a risk management perspective. The following restrictions will be put in place (see also Attachment 5):

The probability of failing to trip the reactor on demand will increase when a RTB train is removed from service, therefore, systems designed for mitigating an ATWS event should be maintained available. RCS pressure relief (pressurizer PORVs and safeties), auxiliary feedwater flow (for RCS heat removal), AMSAC, and turbine trip are important to alternate ATWS mitigation. Therefore, activities that degrade the availability of the auxiliary feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a RTB train is inoperable for maintenance.

Due to the increased dependence on the available reactor trip train when one logic train or one RTB train is inoperable for maintenance, activities that degrade other components of the RTS, including master relays or slave relays, and activities that cause analog channels to be unavailable, should not be scheduled when a logic train or a RTB train is inoperable for maintenance.

Page 16 of 30 Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., essential service water) that support the systems or functions listed in the first two bullets should not be scheduled when a RTB train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

Tier 3, Risk-informed Configuration Risk Management Tier 3 requires a proceduralized process to assess the risk associated with both planned and unplanned work activities. The objective of the third tier is to ensure that the risk impact of out-of-service equipment is evaluated prior to performing any maintenance activity. As stated in Section 2.3 of Regulatory Guide 1.177, "a viable program would be one that is able to uncover risk-significant plant equipment outage configurations in a timely manner during normal plant operation." The third-tier requirement is an extension of the second-tier requirement, but addresses the limitation of not being able to identify all possible risk-significant plant configurations in the second-tier evaluation. Programs and procedures are in place at [Callaway] which serve to address this objective.

[In particular, APA-ZZ-00315, "Configuration Risk Management Program," and EDP-ZZ-01 129, "Callaway Plant Risk Assessment," are an integral part of the work management process at the plant. The Configuration Risk Management Program (CRMP) ensures that configuration risk is assessed (using the PRA-based Safety Monitor, a computer-based program for assessing the impact on plant safety of out of service equipment) and managed prior to initiating any maintenance activity consistent with the requirements of 10 CFR 50.65(a)(4).

The CRMP also ensures that risk is reassessed if an emergent condition results in a plant configuration that has not been previously assessed. Under the CRMP, using the associated Safety Monitor, risk thresholds were established to ensure that average baseline risk is maintained within an acceptable band.

When the administrative limit (Safety Monitor in the Yellow Band) is exceeded, compensatory measures are established to reduce risk (limit unavailability time and implement a contingency plan to restore and/or mitigate the loss of a key safety function). If a risk significant configuration occurs (Safety Monitor in the Red Band), immediate actions are taken to protect redundant/diverse SSCs that are relied upon to mitigate events.]

Page 17 of 30 SE Conditions NRC approval of WCAP-14333 was subject to the following conditions requiring plant-specific information:

1.

Confirm the applicability of the WCAP-14333 analyses for the plant.

2.

Address the Tier 2 and 3 analyses including the Configuration Risk Management Program (CRMP) insights which confirm that these insights are incorporated into the decision making process before taking equipment out of service.

NRC approval of WCAP-1 5376 was subject to the following conditions requiring plant-specific information:

1.

Confirm the applicability of the topical report to the plant and perform a plant-specific assessment of containment failures and address any design or performance differences that may affect the proposed changes.

2.

Address the Tier 2 and Tier 3 analyses including risk significant configuration insights and confirm that these insights are incorporated into the plant-specific configuration risk management program.

3.

The risk impact of concurrent testing of one logic cabinet and associated reactor trip breaker needs to be evaluated on a plant-specific basis to ensure conformance with the WCAP-1 5376-P, Rev. 0 evaluation, and RGs 1.174 and 1.177.

4.

To ensure consistency with the reference plant, the model assumptions for human reliability in WCAP-15376-P, Rev. 0 should be confirmed to be applicable to the plant-specific configuration.

5.

For future digital upgrades with increased scope, integration and architectural differences beyond that of Eagle 21, the staff finds the generic applicability of WCAP-15376-P, Rev. 0 to future digital systems not clear and should be considered on a plant-specific basis.

6.

An additional commitment from the response to NRC RAI Question 18 (Reference 12) requires that each plant will review their setpoint calculation methodology to ascertain the impact of extending the COT Surveillance Frequency from 92 days to 184 days.

Page 18 of 30 WCAP-14333 and WCAP-1 5376 SE Condition 1, Topical Report Applicability Determination In order to address Safety Evaluation (SE) Condition 1 for both WCAPs, Westinghouse issued implementation guidelines for licensees to confirm the analyses are applicable to their plant. See Attachment 6.

WCAP-14333 and WCAP-1 5376 SE Condition 2 SE Condition 2 for both topical reports is addressed above under the Tier 2 and Tier 3 discussions.

WCAP-15376 SE Condition 3 The response to NRC RAI Question 4 in Reference 11 provided the ICCDP for this configuration (both the logic train and associated RTB train out of service) for preventive maintenance for a total time of 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , which is comprised of a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months plus 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to reach Mode 3. The ICCDP for 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months of unavailability for this configuration is 3.2E-07, which meets the Regulatory Guide 1.177 acceptance criteria of less than 5E-07. Since this ICCDP value is based on the logic train and reactor trip breaker being out of service for 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months at the same time, bypassing one logic train and associated RTB train for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for testing will also meet the Regulatory Guide 1.177 ICCDP guideline.

SE Condition 3 is addressed by demonstrating that the WCAP-15376 analysis is applicable. Demonstrating the applicability of the WCAP-1 5376 analysis is discussed in detail in the response to SE Condition 1 (see Attachment 6).

WCAP-15376 SE Condition 4 See Attachment 6.

WCAP-15376 SE Condition 5 This condition does not apply to [Callaway Plant] at this time. Future digital upgrades will require separate evaluation.

Page 19 of 30 WCAP-15376 RAI Question 18 Commitment The response to this RAI in Reference 12 noted that plant-specific RTS and ESFAS setpoint uncertainty calculations and assumptions, including instrument drift, will be reviewed to determine the impact of extending the Surveillance Frequency of the Channel Operational Test (COT) from 92 days to 184 days.

The rack drift term used in the [Callaway] setpoint study is based on the

[92-day interval for COTs. Therefore, an increase to the COT Frequency from 92 days to 184 days will be verified to have no impact on the setpoint study.

After NRC approved the monthly to quarterly COT surveillance interval increases in References 7 and 8, we made a commitment to review as-found and as-left data for one year. No impact on the setpoint study, nominal trip setpoints, allowable values, or surveillance frequencies was experienced. While we do not anticipate any impact in going from 92 days to 184 days, AmerenUE will trend as-found and as-left data under our System Health Program for the 3 representative trip functions analyzed in WCAP-1 5376 (i.e., OTDT, SG level, and pressurizer pressure) for two years (4 data points) after we implement the amendment granting 184-day COTs.]

Plant-Specific Evaluations for Functions not Evaluated Generically

[Insert 7 of TSTF-411 Revision 1 and Insert 14 of TSTF-418 Revision 2 note that ESFAS Function 7.b, Refueling Water Storage Tank (RWST) Level - Low Low Coincident with Safety Injection (SI), was not included in the generic analyses approved in WCAP-10271 (as supplemented), WCAP-14333, or WCAP-1 5376.

In addition, the Environmental Allowance Modifier (EAM) and Trip Time Delay (TTD) circuitry used at Callaway in the Steam Generator (SG) Water Level - Low Low trip functions (RTS Functions 14.c and 14.d; ESFAS Functions 5.e.(3),

5.e.(4), 6.d.(3), and 6.d.(4)) was not included in the generic analyses.

Several utilities completed plant-specific evaluations to demonstrate that the changes in WCAP-1 0271 and its supplements are applicable to functions not generically evaluated. The analyses performed in WCAP-14333 and WCAP-15376 covered representative RTS and ESFAS trip functions, a subset of the comprehensive set of trip functions included in WCAP-10271 and its supplements. Therefore, the changes approved in WCAP-14333 and WCAP-15376 are also applicable to those plant-specific functions with NRC-approved evaluations performed to apply the changes in WCAP-10271 and its supplements. As recognized in Section 11.0 of both WCAP-14333 and Page 20 of 30 WCAP-1 5376, as well as in NRC-approved traveler TSTF-418 Revision 2, additional plant-specific evaluations should not be required.

Callaway performed a plant-specific evaluation of the RWST level, EAM, and TTD functions that were not analyzed generically. NRC approved the plant-specific evaluation in Reference 8, Callaway Amendment 64 dated October 9, 1991 (item 11 on pages 6-7 of the NRC Safety Evaluation). As such, additional evaluations should not be required. Pertinent excerpts from the original evaluation included in the license amendment request (Reference 13) leading to the NRC issuance of Reference 8 are reprinted below and updated to include unavailability data references from WCAP-14333 and WCAP-15376. This information is presented here for completeness only. This evaluation has already been reviewed and approved by NRC for the WCAP-1 0271 changes and its applicability to the changes presented in WCAP-14333 and WCAP-15376 has been established as discussed above.

A separate evaluation was performed that demonstrates the unavailability and risk results presented in Reference 14 for the allowed outage time (AOT) and surveillance test interval (STI) increases analyzed therein are conservative with respect to the results that would be expected for increasing the AOT and STI of the analog channels of ESFAS Functional Unit 7.b. Reference 14 demonstrates that the effects of the analog channel changes have a minimal impact on overall reliability and risk, based on the small relative contribution of analog channels in general to RTS/ESFAS unavailability. The unavailability of the RWST Level - Low Low Coincident with SI ESFAS function (with 2-out-of-4 combinational logic) would be expected to be on the same order of magnitude as that of the high pressurizer pressure reactor trip function due to similarities in logic coincidence and circuit cards in the instrument loops. The high pressurizer pressure reactor trip function was analyzed in Reference 15 and was one of the representative trip functions analyzed in References 1 and 2. Table 3.2-2 of WCAP-10271 Supplement 1-P-A (Reference 15) established the unavailability of the high pressurizer pressure reactor trip function as 1.5 E-4 for the TOP changes. This unavailability, which would be a representative approximation of the unavailability of the RWST Level

- Low Low Coincident with SI ESFAS function for the TOP changes, is generally at least an order of magnitude less than the TOP Case 1 SI signal unavailabilities given on Table 3.6-6 of Reference 14. Therefore, this plant-specific evaluation concludes that the AOT and STI extensions of Reference 14 should be acceptable for ESFAS Functional Unit 7.b since the SI signal unavailability would dominate the automatic ECCS suction switchover signal unavailability (i.e., the RWST level signal

Page 21 of 30 unavailability would be outweighed by the SI signal unavailability whose coincidence is necessary for automatic ECCS suction switchover). The SI signal unavailability is also shown to be at least an order of magnitude higher compared to the pressurizer pressure reactor trip unavailability in WCAP-14333 (compare Tables 7.1 and 7.3) and in WCAP-1 5376 (compare Tables 8.9 and 8.12).

In addition to the generic conclusions regarding the relative insignificance of the analog channels to ESFAS unavailability, the AOT and STI extensions for Steam Generator (SG) Water Level - Low Low trip functions (RTS Functions 14.c and 14.d; ESFAS Functions 5.e.(3), 5.e.(4), 6.d.(3),

and 6.d.(4)) are supported by the following additional considerations:

i)

As discussed in Section 3.4.2 of WCAP-1 1883 (submitted via Reference 16 and approved by Reference 19 for the EAM/TTD modification) and as described in Section 5.5 of the RTD Bypass Licensing Report attached to Reference 17 and approved by Reference 20 (re: Delta-T input to TTD), the mean time between failure (MTBF) values for the 7300 printed circuit cards used in those modifications are sufficiently high that the reliability of the protection systems is not degraded.

ii)

Although the TTD timer modules are unique to the SG Water Level

- Low Low trip functions, they are disabled above 22.41 % rated thermal power.

Based on the above, the 72-hour maintenance Completion Time and 12-hour bypass test allowance from WCAP-14333 are applied to TS 3.3.2 Conditions K, M, and N. Required Action K.1 for RWST Level Low-Low is deleted since it would not make sense to have K.1 require a channel trip within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and K.2 require channel restoration within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Indefinite operation with an inoperable RWST Level Low-Low channel is not allowed in the Callaway TS.]

Deviations from approved TSTF-411 Revision I and TSTF-418 Revision 2

[TS 3.3.1 Condition D is restructured to avoid confusion as to when a flux map for QPTR is required. The version of Condition D approved in TSTF-418 Revision 2 could incorrectly lead an operator to believe that he could pursue just the option of Required Actions D.1.1 and D.1.2, potentially overlooking the requirement to do a flux map for QPTR within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months per the Note above SR 3.2.4.2. In Page 22 of 30 addition, Required Actions with shorter Completion Times (12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ) are supposed to appear before Required Actions with longer Completion Times (72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ) in the D.2.1 and D.2.2 option. The revised Condition D captures the approved changes (bypass time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , maintenance time before tripping of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ), while eliminating the QPTR and formatting confusions.

Callaway does not have installed bypass test capability for analog channels, with the exception of Containment Pressure High-3. The bypass test Notes for plants with that design are not used in the Callaway TS.

No changes are made regarding the RCP Breaker Position RTS trip function since that function is not used at Callaway.

The changes in TSTF-418 Revision 2 regarding the TS 3.3.1 Condition for RTBs are superseded by the changes in TSTF-411 Revision 1. Option 3 of Insert 6 in TSTF-411 Revision 1 is followed.

The changes to TS 3.3.2 Conditions K, M, and N are based on the plant-specific evaluation discussed above.

New TS 3.3.2 Condition S was added to retain the current Required Actions and Completion Times and SR 3.3.2.3 and its Note was revised to apply to the Automatic Actuation Logic and Actuation Relays (MSFIS) for Steam Line Isolation (ESFAS Function 4.c) and for Turbine Trip and Feedwater Isolation (ESFAS Function 5.b) since the Callaway Main Steam and Feedwater Isolation System (MSFIS) logic function is not covered by WCAP-14333-P-A or WCAP-15376-P-A.

The actuation logic and master relays associated with the Containment Purge Isolation Instrumentation (TS 3.3.6) and Control Room Emergency Ventilation System (CREVS) Actuation Instrumentation (TS 3.3.7) are processed through the Solid State Protection System. The STIs for the actuation logic and master relays of the SSPS were relaxed in WCAP-15376. However, during the review and approval of Reference 18, the only SSPS-related entries contained in TS Tables 3.3.6-1 and 3.3.7-1 were for Containment Isolation - Phase A, ESFAS Function 3.a in TS 3.3.2. Therefore, the TSTF-411 Revision 1 changes to STS 3.3.6 and STS 3.3.7 are not required for Callaway's TS.]

Page 23 of 30

5.0 REGULATORY ANALYSIS

This section addresses the standards of 10 CFR 50.92 as well as the applicable regulatory requirements and acceptance criteria.

5.1 NO SIGNIFICANT HAZARDS CONSIDERATION (NSHC)

The proposed amendment would revise Technical Specification (TS) 3.3.1, Reactor Trip System (RTS) Instrumentation, TS 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation, [and TS 3.3.9, Boron Dilution Mitigation System] to adopt the Completion Times, test bypass times, and Surveillance Frequency changes approved by NRC in WCAP-14333-P-A, Revision 1, October 1998 and WCAP-15376-P-A, Revision 1, March 2003. This amendment application is consistent with NRC-approved travelers TSTF-411 Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376)," and TSTF-418 Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)." The proposed changes do not involve a significant hazards consideration based on the three standards set forth in 10 CFR 50.92(c) as discussed below:

(1)

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

Response: No Overall protection system performance will remain within the bounds of the previously performed accident analyses since no hardware changes are proposed. The same reactor trip system (RTS) and engineered safety feature actuation system (ESFAS) instrumentation will continue to be used. The protection systems will continue to function in a manner consistent with the plant design basis. These changes to the Technical Specifications do not result in a condition where the design, material, and construction standards that were applicable prior to the change are altered.

The proposed changes will not modify any system interface. The proposed changes will not affect the probability of any event initiators. There will be no degradation in the performance of or an increase in the number of challenges imposed on safety-related equipment assumed to function during an accident

Page 24 of 30 situation. There will be no change to normal plant operating parameters or accident mitigation performance. The proposed changes will not alter any assumptions or change any mitigation actions in the radiological consequence evaluations in the FSAR.

The determination that the results of the proposed changes are acceptable was established in the NRC Safety Evaluations prepared for WCAP-14333-P-A (issued by letter dated July 15, 1998) and for WCAP-1 5376-P-A (issued by letter dated December 20, 2002). Implementation of the proposed changes will result in an insignificant risk impact. Applicability of these conclusions has been verified through plant-specific reviews and implementation of the generic analysis results in accordance with the respective NRC Safety Evaluation conditions.

The proposed changes to the Completion Times, test bypass times, and Surveillance Frequencies reduce the potential for inadvertent reactor trips and spurious ESF actuations, and therefore do not increase the probability of any accident previously evaluated. The proposed changes do not change the response of the plant to any accidents and have an insignificant impact on the reliability of the RTS and ESFAS signals. The RTS and ESFAS will remain highly reliable and the proposed changes will not result in a significant increase in the risk of plant operation. This is demonstrated by showing that the impact on plant safety as measured by the increase in core damage frequency (CDF) is less than 1.OE-06 per year and the increase in large early release frequency (LERF) is less than 1.OE-07 per year. In addition, for the Completion Time changes, the incremental conditional core damage probabilities (ICCDP) and incremental conditional large early release probabilities (ICLERP) are less than 5.OE-07 and 5.OE-08, respectively. These changes meet the acceptance criteria in Regulatory Guides 1.174 and 1.177. Therefore, since the RTS and ESFAS will continue to perform their functions with high reliability as originally assumed, and the increase in risk as measured by ACDF, ALERF, ICCDP, ICLERP risk metrics is within the acceptance criteria of existing regulatory guidance, there will not be a significant increase in the consequences of any accidents.

The proposed changes do not adversely affect accident initiators or precursors nor alter the design assumptions, conditions, or configuration of the facility or the manner in which the plant is operated and maintained. The proposed changes do not alter or prevent the ability of structures, systems, and components (SSCs) from performing their intended function to mitigate the consequences of an initiating event within the assumed acceptance limits. The proposed changes do not affect the source term, containment isolation, or radiological release assumptions used in evaluating the radiological consequences of an accident previously evaluated. The proposed changes are consistent with safety analysis

Page 25 of 30 assumptions and resultant consequences.

Therefore, this change does not increase the probability or consequences of an accident previously evaluated.

(2)

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

Response: No There are no hardware changes nor are there any changes in the method by which any safety-related plant system performs its safety function. The proposed changes will not affect the normal method of plant operation. No performance requirements will be affected or eliminated. The proposed changes will not result in physical alteration to any plant system nor will there be any change in the method by which any safety-related plant system performs its safety function.

There will be no setpoint changes or changes to accident analysis assumptions.

No new accident scenarios, transient precursors, failure mechanisms, or limiting single failures are introduced as a result of these changes. There will be no adverse effect or challenges imposed on any safety-related system as a result of these changes.

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

(3)

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

Response: No The proposed changes do not affect the acceptance criteria for any analyzed event nor is there a change to any Safety Analysis Limit (SAL). There will be no effect on the manner in which safety limits, limiting safety system settings, or limiting conditions for operation are determined nor will there be any effect on those plant systems necessary to assure the accomplishment of protection functions. There will be no impact on the overpower limit, DNBR limits, FQ, FAH, LOCA PCT, peak local power density, or any other margin of safety. The radiological dose consequence acceptance criteria listed in the Standard Review Plan will continue to be met.

Page 26 of 30 Redundant RTS and ESFAS trains are maintained, and diversity with regard to the signals that provide reactor trip and engineered safety features actuation is also maintained. All signals credited as primary or secondary, and all operator actions credited in the accident analyses will remain the same. The proposed changes will not result in plant operation in a configuration outside the design basis. The calculated impact on risk is insignificant and meets the acceptance criteria contained in Regulatory Guides 1.174 and 1.177. Although there was no attempt to quantify any positive human factors benefit due to increased Completion Times and bypass test times, it is expected that there would be a net benefit due to a reduced potential for spurious reactor trips and actuations associated with testing.

Implementation of the proposed changes is expected to result in an overall improvement in safety, as follows:

a)

Reduced testing will result in fewer inadvertent reactor trips, less frequent actuation of ESFAS components, less frequent distraction of operations personnel without significantly affecting RTS and ESFAS reliability.

b)

Improvements in the effectiveness of the operating staff in monitoring and controlling plant operation will be realized. This is due to less frequent distraction of the operators and shift supervisor to attend to instrumentation Required Actions with short Completion Times.

c)

Longer repair times associated with increased Completion Times will lead to higher quality repairs and improved reliability.

d)

The Completion Time extensions for the reactor trip breakers will provide the utilities additional time to complete test and maintenance activities while at power, potentially reducing the number of forced outages related to compliance with reactor trip breaker Completion Times, and provide consistency with the Completion Times for the logic trains.

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

Conclusion Based on the above, it is concluded that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) and, accordingly, a finding of "no significant hazards consideration" is justified.

Page 27 of 30 5.2 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA The regulatory bases and guidance documents associated with the systems discussed in this amendment application include:

GDC 2 requires that structures, systems, and components important to safety be designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, floods, tsunami, and seiches without the loss of the capability to perform their safety functions.

GDC 4 requires that structures, systems, and components important to safety be designed to accommodate the effects of, and to be compatible with, the environmental conditions associated with the normal operation, maintenance, testing, and postulated accidents, including loss-of-coolant accidents. These structures, systems, and components shall be appropriately protected against dynamic effects, including the effects of missiles, pipe whipping, discharging fluids that may result from equipment failures, and from events and conditions outside the nuclear power unit. However, dynamic effects associated with postulated pipe ruptures in nuclear power units may be excluded from the design basis when analyses reviewed and approved by the Commission demonstrate that the probability of fluid system piping rupture is extremely low under conditions consistent with the design basis for the piping.

GDC-1 3 requires that instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems.

GDC-20 requires that the protection system(s) shall be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences and (2) to sense accident conditions and to initiate the operation of systems and components important to safety.

GDC-21 requires that the protection system(s) shall be designed for high functional reliability and testability.

Page 28 of 30 GDC-22 through GDC-25 and GDC-29 require various design attributes for the protection system(s), including independence, safe failure modes, separation from control systems, requirements for reactivity control malfunctions, and protection against anticipated operational occurrences.

Regulatory Guide 1.22 discusses an acceptable method of satisfying GDC-20 and GDC-21 regarding the periodic testing of protection system actuation functions. These periodic tests should duplicate, as closely as practicable, the performance that is required of the actuation devices in the event of an accident.

10 CFR 50.55a(h) requires that the protection systems meet IEEE 279-1971.

Section 4.2 of IEEE 279-1971 discusses the general functional requirement for protection systems to assure they satisfy the single failure criterion.

There will be no changes to the RTS or ESFAS instrumentation design such that compliance with any of the regulatory requirements and guidance documents above would come into question. The above evaluations confirm that the plant will continue to comply with all applicable regulatory requirements.

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

6.0 ENVIRONMENTAL CONSIDERATION

[AmerenUE] has determined that the proposed amendment would change requirements with respect to the installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, [AmerenUE] has evaluated the proposed amendment and has determined that the amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amount of effluent that may be released offsite, or (iii) a significant increase in the individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22 (c)(9). Therefore, pursuant to 10 CFR 51.22 (b), an environmental assessment of the proposed amendment is not required.

Page 29 of 30

7.0 REFERENCES

1.

WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998.

2.

WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003.

3.

Industry/TSTF Standard Technical Specification Change Traveler TSTF-41 1, Revision 1, Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376)."

4.

Industry/TSTF Standard Technical Specification Change Traveler TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)."

[5.

ULNRC-04258 dated May 25, 2000, "Revision to Technical Specifications 3.3.2, 3.4.10, and 3.4.11 for Pressurizer Safety Valves and PORVs."

6.

Callaway License Amendment 137, "Revision to Technical Specifications 3.3.2, 3.4.10, and 3.4.11 for Pressurizer Safety Valves and PORVs," dated September 25, 2000.

7.

Callaway License Amendment 17, WCAP-1 0271-P-A and WCAP-1 0271 Supplement 1-P-A for the Reactor Trip System," dated September 8, 1986.

8.

Callaway License Amendment 64, 'WCAP-10271-P-A Supplement 2, Revision 1 for the ESFAS," dated October 9, 1991.]

9.

Westinghouse Owners Group letter OG-96-1 10 dated December 20, 1996 (copy included in the back of the approved version of Reference 1 above).

10.

Southern Nuclear Operating Company letters LCV-1364 dated October 13, 1999 and LCV-1364-A dated June 1, 2000, Docket Numbers 50-424 and 50-425.

11.

Westinghouse Owners Group letter OG-02-002 dated January 8, 2002 (copy included in Appendix D of the approved version of Reference 2 above).

Page 30 of 30

12.

Westinghouse Owners Group letter OG-01-058 dated September 28, 2001 (copy included in Appendix D of the approved version of Reference 2 above).

[13.

ULNRC-2381, "WCAP-1 0271-P-A Supplement 2, Revision 1 for the ESFAS," dated March 19,1991.]

14.

WCAP-1 0271-P-A Supplement 2, Revision 1, "Evaluation of Surveillance Frequencies and Out of Service Times for the Engineered Safety Features Actuation System," June 1990.

15.

WCAP-10271-P-A and Supplement 1-P-A, "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System," May 1986.

[16.

ULNRC-1 822, "Steam Generator Level Reactor Trip Modification," dated August 30, 1988.

17.

ULNRC-2196, "RTD Bypass Modification," dated April 12,1990.

18.

Callaway License Amendment 133, "Conversion to Improved Technical Specifications for Callaway Plant, Unit 1," dated May 28, 1999.

19.

Callaway License Amendment 43, "Steam Generator Level Reactor Trip Modification," dated April 14, 1989.

20.

Callaway License Amendment 57, RTD Bypass Modification," dated September 20,1990.]

ATTACHMENT 2 MARKUP OF TECHNICAL SPECIFICATIONS

XA7M~r!!

ACTIONS (continued)

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION D. One Power Range Neutron NOTE Fiqx - High channel The inoperable channel may be ino prable.assed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing and setpoint adjustment of other channels.

D.1.1 Place chan in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND D.1.2 R uce THERMAL 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OWER to < 75% RTP.

D.1 Place channel in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AD

/

D.2.2 OTE---

Only requi d to be performed nthe Power Range utron Flux input to QP is inoperable.

Perform SR 3.2.4.2.

nce per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR D.3 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

CALLAWAY PLANT 3.3-3 Amendment No. 133

INSERT 3.3.1.D CONDITION REQUIRED ACTION COMPLETION D. One Power Range Neutron NOTE Flux - High channel The inoperable channel may be inoperable.

bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing and setpoint adjustment of other channels.

D.1.1 NOTE Only required to be performed when the Power Range Neutron Flux input to QPTR is inoperable with THERMAL POWER >

75% RTP.

Perform SR 3.2.4.2.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND D.1.2 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR D.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION E.

One channel inoperable.

NOTE The inoperable channel may be bypassed for up to hours for surveillance testing ot other channels.

E.1 Place channel in trip.

)hours OR E.2 Be in MODE 3.

hours F.

One Intermediate Range F.1 Reduce THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Neutron Flux channel POWER to < P-6.

inoperable.

OR F.2 Increase THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months POWER to > P-10.

(continued)

CALLAWAY PLANT 3.3-4 Amendment No. 133

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION K.

One Source Range K.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Neutron Flux channel OPERABLE status.

inoperable.

OR K.2.1 Initiate action to fully 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months insert all rods.

AND K.2.2 Place the Rod Control 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months System in a condition incapable of rod withdrawal.

L.

Not used.

M. One channel inoperable.

NOTE The inoperable channel may be bypassed for up to ours for surveillance testing o other channels.

M.1 Place channel in trip.

OR M.2 Reduce THERMAL POWER to < P-7.

(continued)

CALLAWAY PLANT 3.3-6 Amendment No. 133

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME N.

Not used.

0. One Low Fluid Oil Pressure NOTE Turbine Trip channel The inoperable channel may be inoperable.

bypassed for up t ours for surveillance testing o er channels.

0.1 Place channel in trip.

h OR 7a 0.2 Reduce THERMAL

/

hours POWER to < P-9.

7 P.

One or more Turbine Stop R1 Place channel(s) in trip.

hours Valve Closure Turbine Trip 7;2.

channel(s) inoperable.

OR R2 Reduce THERMAL 0hours POWER to < P-9.-76 (continued)

CALLAWAY PLANT 3.3-7 Amendment No. 133

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME Q.

One train inoperable.

_-NOE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

Q.1 Restore train to dhours OPERABLE status.

1 a.

Q.2 Be in MODE 3.

Qhours (3n (continued)

I CALLAWAY PLANT 3.3-8 Amendment No. 133

RTS Instrumentation 3.3.1 ACTIONS (continued)

/---

4 CONDITION REQUIRED ACTION COMPLETION R. One RTB train inoperable.

NOT One in may be bvPassed for up to hours for k~

surveillance testing, provided the other train is OPERABLE.

One RTB may be bypassed y

or the time required for prforming maintenanc on und rvoltage or shu trip mech isms per ndition U, provide e ot r train is OPERABL<

One RT may b ypassed for up to ~ours for logi su illance testing e

ndition Q provided the er rain is OPERABLE.

R.1 Restore train to

)

rs OPERABLE status.

A OR go R.2 Be in MODE 3.

fhours (continued)

CALLAWAY PLANT 3.3-9 Amendment No. 133

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION W. One or more Vessel AT W.1 Place channel(s) in trip.

shours Equivalent channel(s) t7 inoperable.

O W.2 Be in MODE 3.

Xhurs 178 X.

One or more Containment X.1 Place channel(s) in trip.

ihours Pressure - Environmental Allowance Modifier OR channel(s) inoperable.

X.2 Be in MODE 3.

Mjurs 7LP

. :::: :-A CALLAWAY PLANT 3.3-1 1 Amendment No. 133

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.4

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

This Surveillance must be performed on the reactor trip bypass breaker for the local manual shunt trip only prior to placing the bypass breaker in service.

,4a Perform TADOT.

EDdays on a STAGGERED TEST BASIS SR 3.3.1.5 Perform ACTUATION LOGIC TEST.

ays ona STAGGERED TEST BASIS SR 3.3.1.6 N--------NOTE----

Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after achieving equilibrium conditions with THERMAL POWER 2 75 % RTP.

Calibrate excore channels to agree with incore 92 EFPD detector measurements.

SR 3.3.1.7 NOTES----

1.

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

2.

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

Perform COT.

6ays (continued)

CALLAWAY PLANT 3.3-1 3 Amendment No. 133

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE I

FREQUENCY SR 3.3.1.8 NOTE---

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

Perform COT.

NOTE-Only required when not performed within previous2 days Prior to reactor startup AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-10 for power and intermediate instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND h4 Everydays thereafter (continued)

CALLAWAY PLANT 3.3-1 4 Amendment No. 133

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COTIME C. One train inoperable.

NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

C.1 NOTE Only required if Function 3.a.(2) is inoperable.

Place and maintain Immediately containment purge supply and exhaust valves in closed position.

AND C.2 Restore train to phours OPERABLE status.

OR C.3.1 Be in MODE 3.

hours IE30 AND C.3.2 Be in MODE 5.

ehours (ton (continued)

CALLAWAY PLANT 3.3-26 Amendment No. 133

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION D.

One channel inoperable.

NOTE The inoperable channel may be bypassed for up to hours for surveillance testing o other channels.

D.1 Place channel in trip.

hours OR 7

D.2.1 Be in MODE 3.

hours AND D.2.2 Be in MODE 4.

(%hours E. One Containment Pressure NOTE channel inoperable.

One additional channel may be bypassed for up to hours for surveillance testing.

E.1 Place channel in bypass. shours OR E.2.1 Be in MODE 3.

Ithours AND 7

E.2.2 Be in MODE 4.

Itours (continued)

CALLAWAY PLANT 3.3-27 Amendment No. 133

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION F. One channel or train F.1 Restore channel or train 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable.

to OPERABLE status.

OR F.2.1 Be in MODE 3.

54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months AND F.2.2 Be in MODE 4.

60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months G One train inoperable.

NOTE-----

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

GI Restore train to ours OPERABLE status.

OR G2.1 Be in MODE 3.

hours AND G.2.2 Be in MODE 4.

Ohou H. One or more trains NOTED inoperable.

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

H.1 Declare associated Immediately Pressurizer PORV(s) inoperable.

(continued)

CALLAWAY PLANT 3.3-28 Amendment No. 137

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

COMPLETION CONDITION REQUIRED ACTION TME

1.

One channel inoperable.

NOTE The inoperable channel may be bypassed for up to ours for surveillance testing of other channels.

1.1 Place channel in trip.

hours OR 1.2 Be in MODE 3.

Qhours J.

One Main Feedwater NOTE-Pumps trip channel The inoperable channel may be inoperable.

bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for s rveillance testing of other channels.

J.1 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 9R J.2 Be in MODE 3.

7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months (continued)

... - k

'. k. -,,

.;:2:;

CALLAWAY PLANT 3.3-29 Amendment No. 133

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION K. One channel inoperable.

NOTE An inoperable channel may be bypassed for up to bours for

/2 surveillance testing of other channels.

K.1 PlaGO channEl in trip.

6 hurs HIND

-I-.

Restore channel to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months K. I OPERABLE status.

QRa

-. 3.1-Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months

l. 2. /

AND

-.3.

Be in MODE 5.

108 hours0.00125 days 0.03 hours 1.785714e-4 weeks 4.1094e-5 months L.

One or more required L.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months channel(s) inoperable.

required state for existing unit condition.

OR L.2.1 Be in MODE 3.

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

13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months (continued)

CALLAWAY PLANT 3.3-30 Amendment No. 133

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION M.

One or more Vessel AT M.1 Place channel(s) in trip.

hours Equivalent channel(s) inoperable.

OR M.2 Be in MODE 3.

qhours N.

One or more Containment N.1 Place channel(s) in trip.

hours Pressure - Environmental t7:

Allowance Modifier O

channel(s) inoperable.

N.2.1 Be in MODE 3.

hours AND N.2.2 Be in MODE 4.

Hours

0.

One channel inoperable NOTE LCO 3.0.4 is not applicable.

0.1 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 0.2 Restore channel to During OPERABLE status.

performance of the next required COT (continued)

CALLAWAY PLANT

.3.3-31 Amendment No. 133

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION R

One or more channel(s)

R1 Declare associated Immediately inoperable.

auxiliary feedwater pump(s) inoperable.

Q. One train inoperable.

NOTE-One train may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other train is OPERABLE.

Q.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND Q.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months R.

One or both train(s)

R.1 Restore train(s) to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable.

OPERABLE status.

OR R.2.1 Be in MODE 3.

54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months AND R.2.2 Be in MODE 4.

60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months CALLAWAY PLANT 3.3-32 Amendment No. 133

INSERT 3.3.2.S CONDITION REQUIRED ACTION COMPLETION S. One train inoperable.

NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

S.1 Restore train to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OPERABLE status.

OR S.2.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND S.2.2 Be in MODE 4.

18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS

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

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.2.2 Perform ACTUATION LOGIC TEST.

days on a STAGGERED TEST BASIS SR 3.3.2.3

-NOTE --

The continuity check may be excludedg 4,7i 4 a. L 'of ErFq 4.

Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS SR 3.3.2.4 Perform MASTER RELAY TEST.

days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT.

6fdays (continued)

CALLAWAY PLANT 3.3-33 Amendment No. 133

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.6

-NOTE-Not applicable to slave relays K602, K620, K622, K624, K630, K740, etd K741 wy k7514.

Perform SLAVE RELAY TEST.

92 days SR 3.3.2.7 NOTE Verification of relay setpoints not required.

Perform TADOT.

18 months SR 3.3.2.8 NOTE Verification of setpoint not required for manual initiation functions.

Perform TADOT.

18 months SR 3.3.2.9 NOTE This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

Perform CHANNEL CALIBRATION.

18 months (continued)

CALLAWAY PLANT 3.3-34 Amendment No. 133

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(")

4. Steam Line Isolation

a. Manual Initiation 1,2 3

2 F

SR 3.3.2.8 NA

b. Automatic 1,20 3 2 trains G

SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays (SSPS)

c. Automatic 1 20 30 2 trains'o)

SR So --.2 NA Actuation Logic

§ and Actuation Relays (MSFIS)

d. Containment 1,2n') Y) 3 D

SR 3.3.2.1 s 18.3 psig Pressure - High 2 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

e. Steam Line Pressure (1) Low 1,2 O9 3')@

3 per steam D

SR 3.3.2.1 2Ž571 psigC) line SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 (2) Negative 3(9No 3 per steam D

SR 3.3.2.1 s 124 psi" Rate - High line SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 (continued)

(a) The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(b) Above the P-11 (Pressurizer Pressure) Interlock and below P-11 unless the Function is blocked.

(c) Time constants used in the leadlag controller are Ts 2 50 seconds and r2 s 5 seconds.

(g) Below the P-1I (Pressurizer Pressure) Interlock; however, may be blocked below P-1I when safety injection on low steam line pressure is not blocked.

(h) Time constant utilized in the rate/lag controller is Ž 50 seconds.

(i)

Except when all MSIVs are closed.

(o) Each train requires a minimum of two programmable logic controllers to be OPERABLE.

CALLAWAY PLANT 3.3-39 Amendment No. 133

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDONS REQUIREMENTS VALUE(")

5. Turbine Trip and Feedwater Isolation

a. Automatic 1,2° 3° 2 trains G

SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays (SSPS)

SR 3.3.2.14

b. Automatic

1. 2@, 3 2 trainso)

SR 3432-NA Actuation Logic g73 and Actuation Relays (MSFIS)

c. SG Water Level -

1,20 4 per SG I

SR 3.3.2.1 s 79.8% of High High (P-14)

SR 3.3.2.5 Narrow Range SR 3.3.2.9 Instrument SR 3.3.2.10 Span

d. Safety Injection Refer to Function I (Safety Injection) for all initiation functions and requirements.

e. Steam Generator Water Level Low-Low "q (1) Sleam 1, 2. 3 4 per SG D

SR 3.3.2.1 2 25.2% of Generator SR 3.3.2.5 Narrow Range Water Level SR 3.3.2.9 Instrument Low-Low SR 3.3.2.10 Span (Adverse Containment Environment)

(continued)

I (a)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

0)

Except when al MFIVs are dosed.

(o)

Each train requires a minimum of two programmable logic controllers to be OPERABLE.

(q)

Feedwater isolation only.

CALLAWAY PLANT 3.3-40 Amendment No. 157

BDMS 3.3.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.9.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.9.2 NOTE Only required to be performed in MODE 5.

Verify BGV0178 is secured in the closed position.

31 days SR 3.3.9.3 NOTE Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below P-6 interlock.

Perform COT and verify nominal flux multiplication ys setpoint of 1.7.

SR 3.3.9.4 NOTE Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

18 months SR 3.3.9.5 Verify the centrifugal charging pump suction valves 18 months from the RWST open and the CVCS volume control tank discharge valves close in less than or equal to 30 seconds on a simulated or actual actuation signal.

SR 3.3.9.6 Verify one RCS loop is in operation.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months CALLAWAY PLANT 3.3-72 Amendment No. 133

ATTACHMENT 3 RETYPED TECHNICAL SPECIFICATIONS

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION D. One Power Range Neutron NOTE-Flux - High channel The inoperable channel may be inoperable.

bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing and setpoint adjustment of other channels.

D.1.1 NOTE----

Only required to be performed when the Power Range Neutron Flux input to QPTR is inoperable with THERMAL POWER >

75% RTP.

Perform SR 3.2.4.2.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND D.1.2 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR D.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months (continued)

CALLAWAY PLANT 3.3-3 Amendment No.

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION E. One channel inoperable.

NOTES--

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

E.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR E.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months F. One Intermediate Range F.1 Reduce THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Neutron Flux channel POWER to < P-6.

inoperable.

OR F.2 Increase THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months POWER to > P-10.

(continued)

CALLAWAY PLANT 3.3-4 Amendment No.

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION K.

One Source Range K.1 Restore channel to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Neutron Flux channel OPERABLE status.

inoperable.

OR K.2.1 Initiate action to fully 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months insert all rods.

AND K.2.2 Place the Rod Control 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months System in a condition incapable of rod withdrawal.

L.

Not used.

M. One channel inoperable.

N NOTE--

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

M.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR M.2 Reduce THERMAL 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months POWER to < P-7.

(continued)

CALLAWAY PLANT 3.3-6 Amendment No.

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION N. Not used.

0. One Low Fluid Oil Pressure NOTE Turbine Trip channel The inoperable channel may be inoperable.

bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

0.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR 0.2 Reduce THERMAL 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months POWER to < P-9.

P.

One or more Turbine Stop R1 Place channel(s) in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Valve Closure Turbine Trip channel(s) inoperable.

OR P.2 Reduce THERMAL 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months POWER to < P-9.

(continued)

I CALLAWAY PLANT 3.3-7 Amendment No.

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION Q. One train inoperable.

NOTE--

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

Q.1 Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR Q.2 Be in MODE 3.

30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (continued)

I CALLAWAY PLANT 3.3-8 Amendment No.

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION R.

One RTB train inoperable.

NOTES-One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other train is OPERABLE.

R.1 Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR R.2 Be in MODE 3.

30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (continued)

I I

I CALLAWAY PLANT 3.3-9 Amendment No.

RTS Instrumentation 3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION W. One or more Vessel AT W.1 Place channel(s) in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Equivalent channel(s) inoperable.

OR W.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months X. One or more Containment X.1 Place channel(s) in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Pressure - Environmental Allowance Modifier OR channel(s) inoperable.

X.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months I

I I

CALLAWAY PLANT 3.3-1 1 Amendment No.

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.4 NOTE---a This Surveillance must be performed on the reactor trip bypass breaker for the local manual shunt trip only prior to placing the bypass breaker in service.

Perform TADOT.

62 days on a STAGGERED TEST BASIS SR 3.3.1.5 Perform ACTUATION LOGIC TEST.

92 days on a STAGGERED TEST BASIS SR 3.3.1.6 NOTE--

Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after achieving equilibrium conditions with THERMAL POWER 2 75 % RTR Calibrate excore channels to agree with incore 92 EFPD detector measurements.

SR 3.3.1.7 NOTES

1.

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

2.

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

Perform COT.

184 days (continued)

I I

CALLAWAY PLANT 3.3-1 3 Amendment No.

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.8

-aNOTE--

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

Perform COT.

NOTE-Only required when not performed within previous 184 days I

Prior to reactor startup AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-10 for power and intermediate instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND Every 184 days thereafter I

(continued)

CALLAWAY PLANT 3.3-14 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION C. One train inoperable.

NOTE-One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

C.1 NOTE---

Only required if Function 3.a.(2) is inoperable.

Place and maintain containment purge supply and exhaust valves in closed position.

Immediately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months AND C.2 OR Restore train to OPERABLE status.

Be in MODE 3.

Be in MODE 5.

C.3.1 AND 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months 60 hours C.3.2 (continued)

CALLAWAY PLANT 3.3-26 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION D. One channel inoperable.

-- NOTE-The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

D.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR D.2.1 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND D.2.2 Be in MODE 4.

84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months E. One Containment Pressure NOTE---

channel inoperable.

One additional channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

E.1 Place channel in bypass.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR E.2.1 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND E.2.2 Be in MODE 4.

84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months (continued)

CALLAWAY PLANT 3.3-27 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME F. One channel or train F.1 Restore channel or train 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable.

to OPERABLE status.

OR F.2.1 Be in MODE 3.

54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months AND F.2.2 Be in MODE 4.

60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months G. One train inoperable.

NOTE-One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

G.1 Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR G.2.1 Be in MODE 3.

30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months AND G.2.2 Be in MODE 4.

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

One or more trains NOTE-----

inoperable.

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

H.I Declare associated Immediately Pressurizer PORV(s) inoperable.

(continued)

CALLAWAY PLANT 3.3-28 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION One channel inoperable.

NOTE--

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

1.1 Place channel in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR 1.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months J.

One Main Feedwater NOTE----

Pumps trip channel The inoperable channel may be inoperable.

bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of other channels.

J.1 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR J.2 Be in MODE 3.

7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months (continued)

I CALLAWAY PLANT 3.3-29 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION K. One channel inoperable.

NOTE-An inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

K.1 Restore channel to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

OR K.2.1 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND K.2.2 Be in MODE 5.

108 hours0.00125 days 0.03 hours 1.785714e-4 weeks 4.1094e-5 months L.

One or more required L.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months channel(s) inoperable.

required state for existing unit condition.

OR L.2.1 Be in MODE 3.

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

13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months (continued)

I I

I CALLAWAY PLANT 3.3-30 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME M. One or more Vessel AT M.1 Place channel(s) in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Equivalent channel(s) inoperable.

OR M.2 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months N.

One or more Containment N.1 Place channel(s) in trip.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Pressure - Environmental Allowance Modifier OR channel(s) inoperable.

N.2.1 Be in MODE 3.

78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND N.2.2 Be in MODE 4.

84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months

0. One channel inoperable.

NTES LCO 3.0.4 is not applicable.

0.1 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND 0.2 Restore channel to During OPERABLE status.

performance of the next required COT (continued)

CALLAWAY PLANT 3.3-31 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME P. One or more channel(s)

RI Declare associated Immediately inoperable.

auxiliary feedwater pump(s) inoperable.

Q. One train inoperable.

NOTE---

One train may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other train is OPERABLE.

Q.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND Q.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months R.

One or both train(s)

R.1 Restore train(s) to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable.

OPERABLE status.

OR R.2.1 Be in MODE 3.

54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months AND R.2.2 Be in MODE 4.

60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months (continued) I CALLAWAY PLANT 3.3-32 Amendment No.

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION S.

One train inoperable NOTE One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

S.1 Restore train to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OPERABLE status.

OR S.2.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND S.2.2 Be in MODE 4.

18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months CALLAWAY PLANT 3.3-33 Amendment No.

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS

-=

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

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.2.2 Perform ACTUATION LOGIC TEST.

92 days on a STAGGERED TEST BASIS SR 3.3.2.3

-NOTE The continuity check may be excluded from the BOP ESFAS test.

Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS SR 3.3.2.4 Perform MASTER RELAY TEST.

92 days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT.

184 days (continued)

I CALLAWAY PLANT 3.3-34 Amendment No.

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.6 NOTE-Not applicable to slave relays K602, K620, K622, K624, K630, K740, K741, and K750.

Perform SLAVE RELAY TEST.

92 days SR 3.3.2.7

-- NOTE------

Verification of relay setpoints not required.

Perform TADOT.

18 months SR 3.3.2.8 NOTE Verification of setpoint not required for manual initiation functions.

Perform TADOT.

18 months SR 3.3.2.9 NOTE---------

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

Perform CHANNEL CALIBRATION.

18 months (continued)

I CALLAWAY PLANT 3.3-35 Amendment No. -

I

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.10 NOTE--

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

Ž900 psig.

Verify ESF RESPONSE TIMES are within limits.

18 months on a STAGGERED TEST BASIS SR 3.3.2.11 NOTE---

Verification of setpoint not required.

Perform TADOT.

18 months SR 3.3.2.12 Perform COT.

31 days (continued)

CALLAWAY PLANT 3.3-36 Amendment No. -

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.13

-aNOT Only applicable to slave relays K602, K622, K624, K630, K740, and K741.

Perform SLAVE RELAY TEST.

18 months AND Prior to entering MODE 4 when in MODE 5 or 6

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , if not performed within the previous 92 days SR 3.3.2.14 NOTE-Only applicable to slave relays K620 and K750.

Perform SLAVE RELAY TEST.

18 months AND Prior to entering MODE 3 when in MODE 5 or 6

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , if not performed within the previous 92 days CALLAWAY PLANT 3.3-37 Amendment No.

-lI

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(')

1.

Safety Injection

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays (SSPS)

c.

Containment Pressure -

High I

d.

Pressurizer Pressure -

Low 1,2,3,4 1,2,3,4 1,2,3 1,2,3° 2

2 trains 3

4 B

SR 3.3.2.8 C

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 SR 3.3.2.13 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA

< 4.5 psig 2 1834 psig

e.

Steam Line Pressure -

Low 1,2,3° 3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 2 571 psig(c)

2.

Containment Spray

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays (SSPS)

c.

Containment Pressure High - 3 1,2,3,4 1,2,3,4 1,2,3 2 per train, 2 trains 2 trains 4

B SR 3.3.2.8 C

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA s 28.3 psig (continued)

(a) The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(b) Above the P-11 (Pressurizer Pressure) interlock and below P-11 unless the Function is blocked.

(c) Time constants used in the lead/lag controller are T12 50 seconds and T2 5 seconds.

CALLAWAY PLANT 3.3-38 Amendment No. -

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(8)

3.

Containment Isolation

a.

Phase A Isolation (1) Manual 1,2,3,4 2

B SR 3.3.2.8 NA Initiation (2) Automatic 1,2,3,4 2 trains C

SR 3.3.2.2 NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation SR 3.3.2.13 Relays (SSPS)

(3) Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Injection

b. Phase B Isolation (1) Manual 1,2,3,4 2 per train, B

SR 3.3.2.8 NA Initiation 2 trains (2) Automatic 1,2,3,4 2 trains C

SR 3.3.2.2 NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (SSPS)

(3) Contain-1,2,3 4

E SR 3.3.2.1 s 28.3 psig ment SR 3.3.2.5 Pressure SR 3.3.2.9 High - 3 SR 3.3.2.10 (continued)

(a) The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

CALLAWAY PLANT 3.3-39 Amendment No. -lI

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(')

4. Steam Line Isolation

a. Manual Initiation 1,2(), 30' 2

F SR 3.3.2.8 NA

b. Automatic 1,20.) 30 2 trains G

SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays (SSPS)

c. Automatic 1, 2°,3) 2 trainso)

S SR 3.3.2.3 NA Actuation Logic and Actuation Relays (MSFIS)

d. Containment 1,20,3(0 3

D SR 3.3.2.1 s 18.3 psig Pressure - High 2 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

e. Steam Line Pressure (1) Low 1,2, 3) 3 per steam D

SR 3.3.2.1 2 571-psigC) line SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 (2)

Negative 3X9)i 3 per steam D

SR 3.3.2.1

124 psi0h Rate - High line SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 (continued)

(a)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(b)

Above the P-1I (Pressurizer Pressure) Interlock and below P-1I unless the Function is blocked.

(c)

Time constants used in the lead/lag controller are r > 50 seconds and X2 5 5 seconds.

(g)

Below the P-11 (Pressurizer Pressure) Interlock; however, may be blocked below P-11 when safety injection on low steam line pressure is not blocked.

(h)

Time constant utilized in the rate/lag controller is 2 50 seconds.

(i)

Except when all MSIVs are closed.

(o)

Each train requires a minimum of two programmable logic controllers to be OPERABLE.

I CALLAWAY PLANT 3.3-40 Amendment No. _

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUEa)

5. Turbine Trip and Feedwater Isolation

a. Automatic 1,20, 30 2 trains G

SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays (SSPS)

SR 3.3.2.14

b. Automatic 1, 2(D, 30 2 trainso)

S SR 3.3.2.3 NA Actuation Logic and Actuation Relays (MSFIS)

c. SG Water Level -

1,20 4 per SG I

SR 3.3.2.1 s 79.8% of High High (P-14)

SR 3.3.2.5 Narrow Range SR 3.3.2.9 Instrument SR 3.3.2.10 Span

d. Safety Injection Refer to Function I (Safety Injection) for all initiation functions and requirements.

e. Steam Generator Water Level Low-Low~q)

(1) Steam 1, 2 ), 30 4 perSG D

SR 3.3.2.1 2 25.2% of Generator SR 3.3.2.5 Narrow Range Water Level SR 3.3.2.9 Instrument Low-Low SR 3.3.2.10 Span (Adverse Containment Environment)

(continued)

(a) The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

A)

Except when all MFIVs are closed.

(o)

Each train requires a minimum of two programmable logic controllers to be OPERABLE.

(q)

Feedwater isolation only.

CALLAWAY PLANT 3.3-41 Amendment No.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(')

5. Turbine Trip and Feedwater Isolation

e.

Steam Generator Water Level Low-Lowq)

(continued)

(2)

Steam Generator 1(r, 20-r), 30 4 per SG D

SR 3.3.2.1 2 19.8% of Water Level SR 3.3.2.5 Narrow Range Low-Low (Normal SR 3.3.2.9 Instrument Containment SR 3.3.2.10 Span Environment)

(3) VesselAT Equivalent including delay timers - Trip Time Delay (a)

Vessel AT 1,20) 4 M

SR 3.3.2.1

Vessel AT (Power-1)

SR 3.3.2.5 Equivalent to SR 3.3.2.9 13.9% RTP(k SR 3.3.2.10 (b) Vessel AT 1,20) 4 M

SR 3.3.2.1 s Vessel AT (Power-2)

SR 3.3.2.5 Equivalent to SR 3.3.2.9 23.9% RTPQ SR 3.3.2.10 (4) Containment 1, 20, 3) 4 N

SR 3.3.2.1 s 2.0 psig Pressure -

SR 3.3.2.5 Environmental SR 3.3.2.9 Allowance Modifier SR 3.3.2.10 (continued)

(a)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

()

Except when all MFIVs are closed.

(k)

With a time delay s 240 seconds.

(I)

With a time delay s 130 seconds.

(q)

Feedwater isolation only.

(r)

Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

CALLAWAY PLANT 3.3-42 Amendment No. _

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 6 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION SPECIFIED CHANNELS CONDITIONS REQUIREMENTS VALUE(")

CONDITIONS

6. Auxiliary Feedwater

a. Manual Initiation

b. Automatic Actuation Logic and Actuation Relays (SSPS)

c. Automatic Actuation Logic and Actuation Relays (BOP ESFAS) 1,2,3 1,2,3 1,2,3 1/pump 2 trains 2 trains P

SR 3.3.2.8 G

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 Q

SR 3.3.2.3 NA NA NA

d. SG Water Level Low-Low (1)

Steam Generator Water Level Low-Low (Adverse Containment Environment) 1,2,3 4 per SG D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

Ž 25.2% of Narrow Range Instrument Span (2) Steam Generator Water Level Low-Low (Normal Containment Environment) 1(r), 2), 3(o 4 per SG D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

Ž 19.8% of Narrow Range Instrument Span (continued)

(a)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(r)

Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

CALLAWAY PLANT 3.3-43 Amendment No. -

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 7 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION SPECIFIED CHANNELS CONDITIONS REQUIREMENTS VALUE(")

CONDITIONS

6. Auxiliary Feedwater

d. SG Water Level Low-Low (continued)

(3) VesselAT Equivalent including delay timers - Trip Time Delay (a) Vessel AT (Power-1) 1,2 4

M SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 s Vessel AT Equivalent to 13.9% RTP()

(b) Vessel AT (Power-2) 1,2 4

M SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

Vessel AT Equivalent to 23.9% RTPO)

(4) Containment Pressure -

Environmental Allowance Modifier

e. Safety Injection

f. Loss of Offsite Power

g. Trip of all Main Feedwater Pumps 1,2,3 4

N SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 s 2.0 psig Refer to Function I (Safety Injection) for all initiation functions and requirements.

1,2,3 1,2n) 2 trains 2 per pump R

SR 3.3.2.7 SR 3.3.2.10 J

SR 3.3.2.8 NA NA (continued)

(a)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(k)

With a time delay s 240 seconds.

(I)

With a time delay s 130 seconds.

(n)

Trip function may be blocked just before shutdown of the last operating main feedwater pump and restored just after the first main feedwater pump is put into service following performance of its startup trip test.

CALLAWAY PLANT 3.3-44 Amendment No. -

I

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 8 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION SPECIFIED CHANNELS CONDITIONS REQUIREMENTS VALUE<a)

CONDITIONS

6. Auxiliary Feedwater (continued)

h. Auxiliary Feedwater Pump Suction Transfer on Suction Pressure - Low 1,2,3 3

0 SR 3.3.2.1 SR 3.3.2.9 SR 3.3.2.10 SR 3.3.2.12 2 20.64 psia

7. Automatic Switchover to Containment Sump

a. Automatic Actuation Logic and Actuation Relays (SSPS)

b. Refueling Water Storage Tank (RWST) Level -

Low Low Coincident with Safety Injection 1,2,3,4 1,2,3,4 2 trains 4

C SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.13 K

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA 2 35.2%

Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

8. ESFAS Interlocks

a. Reactor Trip, P-4

b. Pressurizer Pressure, P-11 1,2,3 1,2,3 2 per train, 2 trains 3

F SR 3.3.2.11 L

SR 3.3.2.5 SR 3.3.2.9 NA

1981 psig

9. Automatic Pressurizer PORV Actuation

a. Automatic Actuation Logic and Actuation Relays (SSPS) 1,2,3 2 trains H

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.14 NA

b. Pressurizer Pressure - High 1,2,3 4

D SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9

2350 psig (a)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

CALLAWAY PLANT 3.3-45 Amendment No. -

PAM Instrumentation 3.3.3 3.3 INSTRUMENTATION 3.3.3 Post Accident Monitoring (PAM) Instrumentation LCO 3.3.3 APPLICABILITY:

The PAM instrumentation for each Function in Table 3.3.3-1 shall be OPERABLE.

MODES 1, 2 and 3.

ACTIONS

1.

LC-- 3.0.4isnotapplica.

NOTES

1. LCO0 3.0.4 is not applicable.

2.

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION TIME A. One or more Functions with A.1 Restore required channel 30 days one required channel to OPERABLE status.

inoperable.

B. Required Action and B.1 Initiate action in Immediately associated Completion accordance with Time of Condition A not Specification 5.6.8.

met.

(continued)

CALLAWAY PLANT 3.3-4 6 Amendment No. -

I

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION C.

NOTE----

C.1 Restore all but one 7 days Not applicable to hydrogen channel to OPERABLE analyzer channels.

status.

One or more Functions with two or more required channels inoperable.

D. Two hydrogen analyzer D.1 Restore one hydrogen 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months channels inoperable.

analyzer channel to OPERABLE status.

E.

Required Action and E.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C or D Table 3.3.3-1 for the not met.

channel.

F.

As required by Required F.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action E.1 and referenced in Table 3.3.3-1.

AND F.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months G.

As required by Required G.1 Initiate action in Immediately Action E.1 and referenced accordance with in Table 3.3.3-1.

Specification 5.6.8.

CALLAWAY PLANT 3.3-4 7 Amendment No.

-lI

PAM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS NOTE SR 3.3.3.1 and SR 3.3.3.2 apply to each PAM instrumentation Function in Table 3.3.3-1.

SURVEILLANCE FREQUENCY SR 3.3.3.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.3.2 NOTE-Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

18 months CALLAWAY PLANT 3.3-48 Amendment No. _

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 of 2)

Post Accident Monitoring Instrumentation CONDITION REFERENCED FROM REQUIRED REQUIRED FUNCTION CHANNELS ACTION E.1

1.

Neutron Flux

2.

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

3.

RCS Cold Leg Temperature (Wide Range)

4.

RCS Pressure (Wide Range)

5.

Reactor Vessel Level Indicating System (RVLIS)

6.

Containment Normal Sump Water Level

7.

Containment Pressure (Normal Range)

8.

Steam Line Pressure 2

2 2

2 per steam generator 2

2 2

4 2 per steam generator F

F F

F G

9.

10.

11.

12.

13.

Containment Radiation Level (High Range)

Containment Hydrogen Analyzers Pressurizer Water Level Steam Generator Water Level (Wide Range)

Steam Generator Water Level (Narrow Range)

F F

F G

F F

(continued)

CALLAWAY PLANT 3.3-49 Amendment No. -

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 2 of 2)

Post Accident Monitoring Instrumentation CONDITION REFERENCED FROM REQUIRED REQUIRED FUNCTION CHANNELS ACTION E.1

14.

Core Exit Temperature - Quadrant 1 2(a)

F

15.

Core Exit Temperature - Quadrant 2 2(a)

F

16.

Core Exit Temperature - Quadrant 3 2(a)

F

17.

Core Exit Temperature - Quadrant 4 2(a)

F

18.

Auxiliary Feedwater Flow Rate 4

F

19.

Refueling Water Storage Tank Level 2

F (a)

A channel consists of two core exit thermocouples (CETs).

CALLAWAY PLANT 3.3-50 Amendment No.

-lI

Remote Shutdown System 3.3.4 3.3 INSTRUMENTATION 3.3.4 Remote Shutdown System LCO 3.3.4 APPLICABILITY:

The Remote Shutdown System Functions in Table 3.3.4-1 and the required auxiliary shutdown panel (ASP) controls shall be OPERABLE.

MODES 1, 2, and 3.

ACTIONS Ilut

1.

LCO 3.0.4 is not applicable.

2.

Separate Condition entry is allowed for each Function and required ASP control.

CONDITION REQUIRED ACTION COMPLETION A. One or more required A.1 Restore required 30 days Functions inoperable.

Function and required ASP controls to OR OPERABLE status.

One or more required ASP controls inoperable.

B. Required Action and B.1 Be in MODE 3.

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

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months CALLAWAY PLANT 3.3-51 Amendment No. -

Remote Shutdown System 3.3.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.4.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.4.2 NOTE Only required to be performed in MODES 1 and 2 for the turbine-driven AFW pump.

Verify each required auxiliary shutdown panel control 18 months circuit and transfer switch is capable of performing the intended function.

SR 3.3.4.3 NOTES-

1.

Neutron detectors are excluded from CHANNEL CALIBRATION.

2.

Reactor trip breaker and RCP breaker position indications are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION for each required 18 months instrumentation channel.

CALLAWAY PLANT 3.3-52 Amendment No. -

Remote Shutdown System 3.3.4 Table 3.3.4-1 (page 1 of 1)

Remote Shutdown System Functions FUNCTION REQUIRED CHANNELS

1. Source Range Neutron Flux(a) 1

2. Reactor Trip Breaker Position 1 per trip breaker

3. Pressurizer Pressure 1

4. RCS Wide Range Pressure 1

5. RCS Hot Leg Temperature 1

6. RCS Cold Leg Temperature 1

7. SG Pressure I perSG

8. SG Level I perSG

9. AFW Flow Rate 1

10. RCP Breaker Position 1 per pump

11. AFW Suction Pressure 1

12. Pressurizer Level 1

(a) Not required OPERABLE in MODE 1 or in MODE 2 above the P-6 setpoint.

CALLAWAY PLANT 3.3-53 Amendment No. -

I

LOP DG Start Instrumentation 3.3.5 3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation LCO 3.3.5 APPLICABILITY:

Four channels per 4.1 6-kV NB bus of the loss of voltage Function and four channels per 4.1 6-kV NB bus of the degraded voltage Function shall be OPERABLE.

MODES 1, 2, 3, and 4, When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources - Shutdown."

ACTIONS NOTE Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION A.

One or more Functions with A.1 I---

NOTE----

one channel per bus The inoperable channel inoperable.

may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels.

Place channel in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months B. One or more Functions with B.1 Declare associated load Immediately two or more channels per shedder and emergency bus inoperable.

load sequencer (LSELS) inoperable.

OR Required Action and associated Completion Time of Condition A not met.

CALLAWAY PLANT 3.3-54 Amendment No. -

I

LOP DG Start Instrumentation 3.3.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1 Tie breakers between 480 Vac buses NG01 and NG03 7 days and between 480 Vac buses NG02 and NG04 shall be verified open.

SR 3.3.5.2 NOTE----

Verification of time delays is not required.

Perform TADOT.

31 days SR 3.3.5.3 Perform CHANNEL CALIBRATION with nominal Trip 18 months Setpoint and Allowable Value as follows:

a.

Loss of voltage Allowable Value 83 +0, -8.3V (1 20V Bus) with a time delay of 1.0 + 0.2,

-0.5 sec.

Loss of voltage nominal Trip Setpoint 83V (120V Bus) with a time delay of 1.0 sec.

b.

Degraded voltage Allowable Value 107.47 +/- 0.38V (120V Bus) with a time delay of 119 +/- 11.6 sec.

Degraded voltage nominal Trip Setpoint 107.47V (120V Bus) with a time delay of 119 sec.

SR 3.3.5.4 Verify LOP DG Start ESF RESPONSE TIMES are 18 months on a within limits.

STAGGERED TEST BASIS CALLAWAY PLANT 3.3-55 Amendment No. -

I

Containment Purge Isolation Instrumentation 3.3.6 3.3 INSTRUMENTATION 3.3.6 Containment Purge Isolation Instrumentation LCO 3.3.6 APPLICABILITY:

The Containment Purge Isolation instrumentation for each Function in Table 3.3.6-1 shall be OPERABLE.

According to Table 3.3.6-1.

ACTIONS a-- ---

NOTI Separate Condition entry is allowed for each Func CONDITION REQUIRED ACTION COMPLETION A. One radiation monitoring A.1 Restore the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months channel inoperable.

channel to OPERABLE status.

(continued)

CALLAWAY PLANT 3.3-56 Amendment No. -

I

Containment Purge Isolation Instrumentation 3.3.6 ACTIONS (continued)

.._. _ _ \\

~~~~~COMPLETION CONDITION REQUIRED ACTION TIME B. -

- NOTE---

B.1 Place and maintain Immediately Only applicable in MODE 1, containment purge 2, 3, or 4.

supply and exhaust valves in closed position.

One or more Functions with one or more manual channels or automatic actuation trains inoperable.

OR Both radiation monitoring channels inoperable.

OR Required Action and associated Completion Time of Condition A not met.

(continued)

CALLAWAY PLANT 3.3-57 Amendment No. -

Containment Purge Isolation Instrumentation 3.3.6 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION C.

NOTE C.1 Place and maintain Immediately Only applicable during containment purge CORE ALTERATIONS or supply and exhaust movement of irradiated fuel valves in closed position.

assemblies within containment.

OR C.2 Enter applicable Immediately One or more manual Conditions and Required channels inoperable.

Actions of LCO 3.9.4, "Containment Penetrations," for containment purge supply and exhaust valves made inoperable by isolation instrumentation.

CALLAWAY PLANT 3.3-58 Amendment No. -

I

Containment Purge Isolation Instrumentation 3.3.6 SURVEILLANCE REQUIREMENTS NOTE Refer to Table 3.3.6-1 to determine which SRs apply for each Containment Purge Isolation Function.

SURVEILLANCE FREQUENCY SR 3.3.6.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.2 NOTE The continuity check may be excluded.

Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS SR 3.3.6.3 Perform COT.

92 days SR 3.3.6.4 NOTE -

Verification of setpoint is not required.

Perform TADOT.

18 months SR 3.3.6.5 Perform CHANNEL CALIBRATION.

18 months SR 3.3.6.6 Verify Containment Purge Isolation ESF RESPONSE 18 months on a TIMES are within limits.

STAGGERED TEST BASIS CALLAWAY PLANT 3.3-59 Amendment No. _

Containment Purge Isolation Instrumentation 3.3.6 Table 3.3.6-1 (page 1 of 1)

Containment Purge Isolation Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE NOMINAL FUNCTION CONDITIONS CHANNELS REQUIREMENTS TRIP SETPOINT

1.

Manual 1,2.3,4, 2

SR 3.3.6.4 NA Initiation (a), (b)

2.

Automatic 1,2,3.4 2 trains SR 3.3.6.2 NA Actuation SR 3.3.6.6 Logic and Actuation Relays (BOP ESFAS)

3.

Containment 1,2,3,4 2

SR 3.3.6.1 (c)

Purge SR 3.3.6.3 Exhaust SR 3.3.6.5 Radiation -

Gaseous

4.

Containment Refer to LCO 3.3.2, ESFAS Instrumentation," Function 3.a, for all initiation functions and Isolation -

requirements.

Phase A (a)

During CORE ALTERATIONS.

(b)

During movement of irradiated fuel assemblies within containment.

(c)

Set to ensure ODCM limits are not exceeded.

CALLAWAY PLANT 3.3-60 Amendment No. -

CREVS Actuation Instrumentation 3.3.7 3.3 INSTRUMENTATION 3.3.7 Control Room Emergency Ventilation System (CREVS) Actuation Instrumentation LCO 3.3.7 The CREVS actuation instrumentation for each Function in Table 3.3.7-1 shall be OPERABLE.

APPLICABILITY:

ACTIONS According to Table 3.3.7-1.

aI I

-NIL I r- ---

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION A.

One or more Functions with A.1 Place one CREVS train 7 days one channel or train in Control Room inoperable.

Ventilation Isolation Signal (CRVIS) mode.

(continued)

-N CALLAWAY PLANT 3.3-61 Amendment No.

I

CREVS Actuation Instrumentation 3.3.7 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION B.

NOTE B.1.1 Place one CREVS train Immediately Not applicable to in CRVIS mode.

Function 3.

AND One or more Functions with B.1.2 Enter applicable Immediately two channels or two trains Conditions and Required inoperable.

Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)", for one CREVS train made inoperable by inoperable CREVS actuation instrumentation.

OR B.2 Place both trains in Immediately CRVIS mode.

(continued)

CALLAWAY PLANT 3.3-62 Amendment No. -

CREVS Actuation Instrumentation 3.3.7 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME C.

Both radiation monitoring C.1.1 Enter applicable Immediately channels inoperable.

Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)," for one CREVS train made inoperable by inoperable CREVS actuation instrumentation.

AND C.1.2 Place one CREVS train 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in CRVIS mode.

OR C.2 Place both trains in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months CRVIS mode.

D. Required Action and D.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time for Conditions A, B, AND or C not met in MODE 1, 2, 3, or 4.

D.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months E. Required Action and E.1 Suspend CORE Immediately associated Completion ALTERATIONS.

Time for Conditions A, B, or C not met in MODE 5 or 6, AND or during CORE ALTERATIONS, or during E.2 Suspend movement of Immediately movement of irradiated fuel irradiated fuel assemblies.

assemblies.

CALLAWAY PLANT 3.3-63 Amendment No. -

I

CREVS Actuation Instrumentation 3.3.7 SURVEILLANCE REQUIREMENTS NOTE-Refer to Table 3.3.7-1 to determine which SRs apply for each CREVS Actuation Function.

SURVEILLANCE FREQUENCY SR 3.3.7.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.7.2 Perform COT.

92 days SR 3.3.7.3 NOTE The continuity check may be excluded.

Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS SR 3.3.7.4 a

-NOTE-Verification of setpoint is not required.

Perform TADOT.

18 months SR 3.3.7.5 Perform CHANNEL CALIBRATION.

18 months SR 3.3.7.6 NOTE Radiation monitor detectors are excluded from response time testing.

Verify Control Room Ventilation Isolation ESF 18 months on a RESPONSE TIMES are within limits STAGGERED TEST BASIS CALLAWAY PLANT 3.3-64 Amendment No. -lI

CREVS Actuation Instrumentation 3.3.7 Table 3.3.7-1 (page 1 of 1)

CREVS Actuation Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE TRIP FUNCTION CONDITIONS CHANNELS REQUIREMENTS SETPOINT

1.

Manual 1,2,3,4,5,6, 2

SR 3.3.7.4 NA Initiation (a), and (c)

2.

Automatic 1,2, 3, 4, 5, 6, 2 trains SR 3.3.7.3 NA Actuation (a), and (c)

Logic and Actuation Relays (BOP (a) 2 trains SR 3.3.7.6 NA ESFAS)

3.

Control Room 1, 2, 3, 4, 5, 6, 2

SR 3.3.7.1 (b)

Radiation -

and (a)

SR 3.3.7.2 Control Room SR 3.3.7.5 Air Intakes (a) 2 SR 3.3.7.6 (b)

4.

Containment Refer to LCO 3.3.2, ESFAS Instrumentation," Function 3.a, for all initiation functions and Isolation -

requirements.

Phase A

5.

Fuel Building Refer to LCO 3.3.8, "EES Actuation Instrumentation," for all initiation functions and Exhaust requirements' Radiation-Gaseous (a)

During CORE ALTERATIONS or during movement of irradiated fuel assemblies within containment.

(b)

Nominal Trip Setpoint concentration value (pCicM3) shall be established such that the actual submersion dose rate would not exceed 2 mR/hr in the control room.

(c)

During movement of irradiated fuel assemblies in the fuel building CALLAWAY PLANT 3.3-65 Amendment No. -

I

EES Actuation Instrumentation 3.3.8 3.3 INSTRUMENTATION 3.3.8 Emergency Exhaust System (EES) Actuation Instrumentation LCO 3.3.8 The EES actuation instrumentation for each Function in Table 3.3.8-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.8-1.

ACTIONS NnOr- ---

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION A.

One or more Functions A.1 Place one EES train in 7 days with one channel or train the Fuel Building inoperable.

Ventilation Isolation Signal (FBVIS) mode.

AND A.2 Place one CREVS train 7 days in Control Room Ventilation Isolation Signal (CRVIS) mode.

(continued)

CALLAWAY PLANT 3.3-66 Amendment No. _

EES Actuation Instrumentation 3.3.8 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME B.

NOTE----

Not applicable to Function 3.

B.1.1 Place one EES train in the FBVIS mode and one CREVS train in the CRVIS mode.

One or more Functions with two channels or two trains inoperable.

AND B.1.2 Enter applicable Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)," for one CREVS train made inoperable and enter applicable Conditions and Required Actions of LCO 3.7.13, "Emergency Exhaust System (EES),"

for one EES train made inoperable by inoperable EES actuation instrumentation.

Immediately Immediately Immediately OR B.2 Place both EES trains in the FBVIS mode and both CREVS trains in the CRVIS mode.

(continued)

CALLAWAY PLANT 3.3-67 Amendment No.

-i

EES Actuation Instrumentation 3.3.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION

_~~

I__

TIME C.

Both radiation monitoring channels inoperable.

C.1.1 Enter applicable Conditions and Required Actions of LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)," for one CREVS train made inoperable and enter applicable Conditions and Required Actions of LCO 3.7.13, "Emergency Exhaust System EES),"

for one EES train made inoperable by inoperable EES actuation instrumentation.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour AND C.1.2 Place one EES train in the FBVIS mode and one CREVS train in the CRVIS mode.

OR C.2 Place both EES trains in the FBVIS mode and both CREVS trains in the CRVIS mode.

D.

Required Action and D.1 Suspend movement of Immediately associated Completion irradiated fuel Time for Conditions A, B, assemblies in the fuel or C not met during building.

movement of irradiated fuel assemblies in the fuel building.

CALLAWAY PLANT 3.3-68 Amendment No.

I

EES Actuation Instrumentation 3.3.8 SURVEILLANCE REQUIREMENTS

-NOTE Refer to Table 3.3.8-1 to determine which SRs apply for each EES Actuation Function.

SURVEILLANCE FREQUENCY SR 3.3.8.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.8.2 Perform COT.

92 days SR 3.3.8.3

-NOTE The continuity check may be excluded.

Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS SR 3.3.8.4 NOTE---

Verification of setpoint is not required.

Perform TADOT.

18 months SR 3.3.8.5 Perform CHANNEL CALIBRATION.

18 months CALLAWAY PLANT 3.3-69 Amendment No. -

I

EES Actuation Instrumentation 3.3.8 Table 3.3.8-1 (page 1 of 1)

EES Actuation Instrumentation APPLICABLE MODES OR SPECIFIED REQUIRED SURVEILLANCE NOMINALTRIP FUNCTION CONDITIONS CHANNELS REQUIREMENTS SETPOINT

1.

Manual (a) 2 SR 3.3.8.4 NA Initiation

2.

Automatic (a) 2 trains SR 3.3.8.3 NA Actuation Logic and Actuation

'Relays (BOP ESFAS)

3.

Fuel (a) 2 SR 3.3.8.1 (b)

Building SR 3.3.8.2 Exhaust SR 3.3.8.5 Radiation

- Gaseous (a)

During movement of irradiated fuel assemblies in the fuel building.

(b)

Nominal Trip Setpoint concentration value (pCicm3) shall be established such that the actual submersion dose rate would not exceed 4 mR/hr in the fuel building.

CALLAWAY PLANT 3.3-70 Amendment No. -

I

BDMS 3.3.9 3.3 INSTRUMENTATION 3.3.9 Boron Dilution Mitigation System (BDMS)

LCO 3.3.9 APPLICABILITY:

Two trains of the BDMS shall be OPERABLE and one RCS loop shall be in operation.

MODES 2 (below P-6 (Intermediate Range Neutron Flux) interlock), 3, 4, and 5.

NOTE-----

The boron dilution flux multiplication signal may be blocked in MODES 2 (below P-6 (Intermediate Range Neutron Flux) interlock) and 3 during reactor startup.

ACTIONS CONDITION REQUIRED ACTION TIME A.

One train inoperable.

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

B. Two trains inoperable.

B.1 NOTE---

Plant temperature OR changes are allowed provided the temperature Required Action and change is accounted for associated Completion in the calculated SDM.

Time of Condition A not met.

Suspend operations Immediately involving positive reactivity additions.

AND (continued)

CALLAWAY PLANT 3.3-71 Amendment No. -

I

BDMS 3.3.9 ACTIONS CONDITION REQUIRED ACTION TIME B. (continued)

B.2 Perform SR 3.1.1.1.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.3.1 Close and secure 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months unborated water source isolation valves, BGV0178 and BGV0601.

AND B.3.2 Verify unborated water Once per 31 days source isolation valves, BGV0178 and BGV0601, are closed and secured.

C. No RCS loop in operation.

C.1 Close and secure 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months unborated water source isolation valves, BGV0178 and BGV0601.

AND C.2 Verify unborated water Once per 31 days source isolation valves, BGV0178 and BGV0601, are closed and secured.

CALLAWAY PLANT 3.3-72 Amendment No. -

BDMS 3.3.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.9.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.9.2

=NOTE Only required to be performed in MODE 5.

Verify BGV0178 is secured in the closed position.

31 days SR 3.3.9.3 TNOTE -

Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below P-6 interlock.

Perform COT and verify nominal flux multiplication setpoint of 1.7.

184 days l

SR 3.3.9.4 NOTE Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

18 months SR 3.3.9.5 Verify the centrifugal charging pump suction valves 18 months from the RWST open and the CVCS volume control tank discharge valves close in less than or equal to 30 seconds on a simulated or actual actuation signal.

SR 3.3.9.6 Verify one RCS loop is in operation.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months CALLAWAY PLANT 3.3-73 Amendment No.

ATTACHMENT 4 PROPOSED TECHNICAL SPECIFICATION BASES CHANGES (for information only)

RTS Instrumentation B 3.3.1 BASES ACTIONS C.1, C.2.1, and C.2.2 (continued)

Condition C applies to the following reactor trip Functions in MODE 3, 4, or 5 with the Rod Control System capable of rod withdrawal or one or more rods not fully inserted:

Manual Reactor Trip; RTBs; RTB Undervoltage and Shunt Trip Mechanisms; and Automatic Trip Logic.

This action addresses the train orientation of the RTS for these Functions.

With one channel or train inoperable, the inoperable channel or train must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . If the affected Function(s) cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time, the unit must be placed in a MODE in which the requirement does not apply. To achieve this status, action must be initiated within the same 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months to fully insert all rods and the Rod Control System must be rendered incapable of rod withdrawal within the next hour (e.g., by de-energizing all CRDMs, by opening the RTBs, or de-energizing the motor generator (MG) sets). The additional hour for the latter provides sufficient time to accomplish the action in an orderly manner. With the rods fully inserted and the Rod Control System incapable of rod withdrawal, these Functions are no longer required.

The Completion Time is reasonable considering that in this Condition, the remaining OPERABLE train is adequate to perform the safety function, and given the low probability of an event occurring during this interval.

Condition C is modified by a Note stating that while this LCO is not met for Function 19, 20, or 21 in MODE 5, making the Rod Control System capable of rod withdrawal is not permitted. This Note specifies an exception to LCO 3.0.4 for this MODE 5 transition and avoids placing the plant in a condition where control rods can be withdrawn or not fully inserted while the reactor trip system is degraded.

D.1.1, D.1.2, D 1, D.2.2, a-nd D.3

)

b.2 Condition D applies to the Power Range Neutron Flux - High trip Function.

(continued)

CALLAWAY PLANT B 3.3.1-34 Revision 0

RTS Instrumentation B 3.3.1 BASES r

b.2 ACTIONS D.1.1, D.1.2,'2--

.--.2, ad D.3-(continued)

The NIS power range detectors provide input to the Rod Control System and the SG Water Level Control System and, therefore, have a

-TM..FeRT-two-out-of-four trip logic. A known inoperable channel must be placed in the tripped condition. This results in a partial trip condition requiring only one-out-of-three logic for actuation. The hours allowed to place the inoperable channel in the tripped condition is justified in Reference 7;2 r-/7 ddition to placing the inoperable channel in the tripped conMin THER OWER must be reduced to < 75% RTP within 12 hou Reducing the er level prevents operation of the core withal power distributions beyon design limits at a power level DNB conditions may exist.

i e of the NIS powe ge detectors inoperable, 1/4 of the radial po distrib nitoring capability is lost.

As an alternative to the above act t

noperable channel can be placed in the tripped conditio thin 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months the QPTR monitored once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months as SR 3.2.4.2 (including t R 3.2.4.2 Note),

QPTR verification.

culating QPTR every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months co nsates for the lost monito capability due to the inoperable NIS power ge channel a Ilows continued unit operation at power levels > 75 TP.

\\ The 6

ur Completion Time and the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency are consiste CO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)."

As an alternative to the above Actions, the plant must be placed in a MODE where this Function is no longer required OPERABLE. Twelve Seve a-e

-i (

) hours are allowed to place the plant in MODE 3. This is a reasonable 7

time, based on operating experience, to reach N4DE 3 from full power in v7 an orderly manner and without challenging plan systems. If Required Actions cannot be completed within their allowei Completion Times, LCO 3.0.3 must be entered.

-X Asc-* /.9 The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to hours while performing routine surveillance testing of other channels.

he Note also allows placing the inoperable channel in the bypassed con tion to allow setpoint adjustments of other channels when required to re uce the setpoint in accordance with other Technical Specifications. rhe hour time limit is justified in References 17.

(

/:

LRequ Action 9. 2 has n modifi by a No which y requs 5 Rt.2.4.2 to perfo if the P er Rang eutron ux inp o

QPTR be es mop ble. Fail e of a co ponent i e Po r Ran Neu~trolux ChantI which r ders theigh Flux p Functin

/1 (continued)

CALLAWAY PLANT B 3.3.1-35 Revision 0

INSERT 1 With one of the NIS power range detectors inoperable, 1/4 of the radial power distribution monitoring capability is lost. Therefore, QPTR must be monitored once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months as per SR 3.2.4.2 (including the SR 3.2.4.2 Note), QPTR verification. Calculating QPTR every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months compensates for the lost monitoring capability due to the inoperable NIS power range channel. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is consistent with LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)."

Required Action D.1.1 has been modified by a Note which only requires SR 3.2.4.2 to be performed if the Power Range Neutron Flux input to QPTR becomes inoperable and the THERMAL POWER is > 75% RTP. Failure of a component in the Power Range Neutron Flux Channel which renders the High Flux Trip Function inoperable may not affect the capability to monitor QPTR. As such, determining QPTR using the movable incore detectors once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months may not be necessary. At power levels less than or equal to 75% RTP, operation of the core with radial power distributions beyond the design limits, at a power level where DNB conditions may exist, is prevented.

INSERT 1 B The 78-hour Completion Time includes 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for channel corrective maintenance, and an additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for the MODE reduction as required by Required Action D.2.

RTS Instrumentation B 3.3.1 BASES ACTIONS D.1.1,.

.2, and D.3 (continued) inoperable may not affect te c.

As such, determining QPH e

movable incore detece12 hours m

necessary.

/

E.1 and E.2 Condition E applies to the following reactor trip Functions:

Power Range Neutron Flux - Low; Overtemperature AT; Overpower AT; Power Range Neutron Flux - High Positive Rate; Pressurizer Pressure - High; SG Water Level - Low Low (Adverse Containment Environment);

and SG Water Level - Low Low (Normal Containment Environment).

A know inoperable channel must be placed in the tripped condition within Hours. Placing the hannel in the tripped condition results in a partial trip condition requirifg only one-out-of-two logic for actuation of the two-out-of-three trips and qne-out-of-three logic for actuation of the two-out-of-four trips. The hours allowed to place the inoperable channel in the tripped condition is justified in Referenced /7.

If the inoperable channel cannot be placed in the tripped condition within the specified Completion Time, the unit must be placed in a MODE where these Functions are not required OPERABLE. An additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed to place the unit in MODE 3. Six hours is a reasonable time, based on operating experience, to place the unit in MODE 3 from full power in an orderly manner and without challenging unit systems.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to hours while performing routine surveillance testing of the other channel. The our time limit is justified in Reference 17.

(continued)

CALLAWAY PLANT B 3.3.1-36 Revision 0

RTS Instrumentation B 3.3.1 BASES ACIONS (continuer d)

J.1 Condition J applies to two inoperable Source Range Neutron Flux trip channels when in MODE 2 below the P-6 setpoint or in MODE 3, 4, or 5 with the Rod Control System capable of rod withdrawal or one or more rods not fully inserted. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With both source range channels inoperable, the Reactor Trip Breakers (RTBs) must be opened immediately. With the RTBs open, the core is in a more stable condition.

I K.1, K2.1, and K.2.2 Condition 1K.applies.to one inoperable source range channel in MODE'3, 4, or 5.with

'he Rod Control System capable of rod withdrawal or one or more rods not fully inserted..Wth the unit in this Condition, below P-,'

-the NIS source range. performs the monitoring and protection functions.

With.oneo-the source range channels inoperable, 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is allowed to restoreit toan OPERABLE status. If the channel cannot be returned to

-an OPERABLE status,.action must be initiated within the same 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months to fully insdrt.al rods. One additional hour is allowed to place the Rod Control System in a condition incapable of rod withdrawal (e.g., by de-energizing all CRDMs, by opening the RTBs, or de-energizing the motor generator (MG).sets). Once these ACTIONS are completed, the core is in a more stable condition. The allowance of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months to restore the channel to OPERABLE status, and the additional hour to place the Rod ontrol Systenm in.a condition incapable of rod withdrawal, are j"~i,,od in Roferanco 5. Normal plant control operations that individually.

add limited positive reaqivity (i.e., temperature or boron concentration fluctuations associated th RCS inventory management or temperature control.re permitted' ovided the SDM limits specified in the COLR are met and.ihe.iriiaiMni' "tical boron concentration assumptions in FSAR Section15.4.6 (Ref.71) are satisfied. Introduction of reactor makeup water into the RCS fr the Chemical and Volume Control System mixing tee is not permitted when one source range neutron flux channel is inoperable.

ass A

LI, L.2, and L.3 Not used.

(continued)

CALLAWAY PLANT B 3.3.1-39 Revision.3

INSERT 1A reasonable considering the other source range channel remains OPERABLE to perform the safety function and given the low probability of an event occurring during this interval.

RTS Instrumentation B 3.3.1 BASES ACTIONS M.1 and M.2 (continued)

Condition M applies to the following reactor trip Functions:

Pressurizer Pressure - Low; Pressurizer Water Level - High; Reactor Coolant Flow - Low; Undervoltage RCPs; and Underfrequency RCPs.

7.2 With one channel inoperabIe( the inoperable channel must be placed in the tripped condition within hours. For the Pressurizer Pressure - Low, Pressurizer Water Level - High, Undervoltage RCPs, and Underfrequency RCPs trip Functions, placing the channel in the tripped condition when above the P-7 setpoint results in a partial trip condition requiring only one additional channel to initiate a reactor trip. For the Reactor Coolant Flow

- Low trip Function, placing the channel in the tripped condition when above the P-8 setpoint results in a partial trip condition requiring only one additional channel in the same loop to initiate a reactor trip. For the Reactor Coolant Flow - Low trip Function, two tripped channels in two RCS loops are required to initiate a reactor trip when below the P-8 setpoint and above the P-7 setpoint. These Functions do not have to be OPERABLE below the P-7 setpoint because there are no loss of flow trips below the P-7 setpoint. There is insufficient heat production to generate DNB conditions below the P-7 setpoint. The fhours allowed to place the channel in the tripped condition is justified in eference 0 An additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed to reduce THERMAL POWER to below P-7 if the inoperable channel cannot be restored to OP RABLE s us or placed in trip within the specified Completion Time.

J 17.

Allowance of this time interval takes into consideration the redundant capability provided by the remaining redundant OPERABLE channels, and the low probability of occurrence of an event during this period that may require the protection afforded by the Functions associated with Condition M.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to hours while performing routine surveillance testing of the other channel. The hour time limit is justified in References i L

(continued)

CALLAWAY PLANT B 3.3.1-40 Revision 3

RTS Instrumentation B 3.3.1 BASES ACTIONS N.1 and N.2 (continued)

Not used.

0.1 and 0.2 72 Condition 0 applies to the Turbine Tri - Low Fluid Oil Pressure trip Function. With one channel inoperab, the inoperable channel must be placed in the tripped condition within hours. If placed in the tripped condition, this results in a partial trip condition requiring only one additional channel to initiate a reactor trip. If the channel cannot be restored to OPERABLE status or placed in the tripped condition, then power must be reduced below the P-9 setpoint within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

'7,2 rlhe hours allowed to place the inoperable channel in the tripped condition and the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allowed for reducing power are justified in Referenced /7.

The Required Actions have been modified by a Note that allows placing an inoperable channel in the bypassed condition for up to hours while performing routine surveillance testing of the other channel The <<hour time limit is justified in References /17.

P.1 and P.2 72 Condition P applies to the Turbine Trip - Turbine Stop Valv losure trip Function. With one or more channel(s) inoperable, the in perable channel(s) must be placed in the tripped condition within hours. For the Turbine Trip - Turbine Stop Valve Closure trip Function, four of four channels are required to initiate a reactor trip; hence, more than one channel may be placed in trip. If the channels cannot be restored to OPERABLE status or placed in the tripped condition, then power must be reduced below the P-9 setpoint within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The ours allowed to place the inoperable channels in the tripped dition and the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allowed for reducing power are justified in R rence

/7.

72 Q.1 and Q.2 Condition Q applies to the SI Input from ESFAS reactor trip and the RTS Automatic Trip Logic in MODES 1 and 2. These actions address the train orientation of the RTS for these Functions. With one train inoperable, 24- @hours are allowed to restore the train to OPERABLE status (Required Action Q.1) or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The Completion Time of Itours (Required Action Q.1) is reasonable

~24 (continued)

CALLAWAY PLANT B 3.3.1-41 Revision 3

RTS Instrumentation B 3.3.1 BASES ACTIONS Q.1 and Q.2 (continued) r s4er-2 considering that in this Condi n, the remaining OPERABLE train is adequate to perform the safety function and given the low probability of an event during this interval.

he Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (Required Action Q.2) is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems.

The Required Actions have been modified by a Note that allows bypassing one train up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other train is OPERABLE.

R.1 and R.2

.- 24 Aul-s *ee

/

4 4`4 er-iV I /'4nftr4 4P1 ee Condition R ap: lies to the RTBs in MODES 1 and 2. These actions address the traiorientation of the RTS for the RTBs. With one train inoperable, t

o restore the train to OPERABLE status or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .A.The __CA/Sir59T 5 -sqdovw Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating 3

experience, to reach MODE 3 from full power in an orderly manner and without challenging unit stm.Fnaouan r

D g

(/the eafntza wpl§ gfzRT>utior0J~acing the unit in MODE 3 resufis in ondition entry if one B train is inoperable and the Rod Control System is capable of rod withdrawal or one or more rods are not fully inserted.

ijR irections have been modified by three Notes.

o Sne Gas sed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months fr RTB S provided the othertoeP-6ABLE. N ocs one RTB to be bypassed only for the time re, teintenance on undervoltage or shunt tr theexsn ition ithi or RTB rain is OPER 3 allows ne nt6hs.erfy p to interloc su s surveillance testing per on o assocother OPE ABLE. The time limits are justified in References 5tne S.1 and S.2 Condition S applies to the P-6 and P-10 interlocks. With one or more required channel(s) inoperable, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Verifying the interlock status manually, e.g., by observation of the associated (continued)

CALLAWAY PLANT B 3.3.1-42 Revision 3

INSERT 2 The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed to restore the inoperable train to OPERABLE status is justified in Reference 17.

INSERT 2A Consistent with the requirement in Reference 17 to include Tier 2 insights into the decision-making process before taking equipment out of service, restrictions on concurrent removal of certain equipment when a logic train is inoperable for maintenance are included (note that these restrictions do not apply when a logic train is being tested under the 4-hour bypass Note of Condition Q). Entry into Condition Q is not a typical, pre-planned evolution during power operation, other than for surveillance testing. Since Condition Q is typically entered due to equipment failure, it follows that some of the following restrictions may not be met at the time of Condition Q entry. If this situation were to occur during the 24-hour Completion Time of Required Action Q.1, the Configuration Risk Management Program will assess the emergent condition and direct activities to restore the inoperable logic train and exit Condition Q or fully implement these restrictions or perforrh a plant shutdown, as appropriate from a risk management perspective.

The following restrictions will be observed:

To preserve ATWS mitigation capability, activities that degrade the availability of the auxiliary feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a logic train is inoperable for maintenance.

To preserve LOCA mitigation capability, one complete ECCS train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

To preserve reactor trip and safeguards actuation capability, activities that cause master relays or slave relays in the available train to be unavailable and activities that cause analog channels to be unavailable should not be scheduled when a logic train is inoperable for maintenance.

Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., essential service water and component cooling water) that support the systems or functions listed in the first three bullets should not be scheduled when a logic train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

INSERT 3 The 24-hour Completion Time is justified in Reference 18.

INSERT 4 The Required Actions have been modified by a Note. The Note allows one train to be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other train is OPERABLE. The 4-hour time limit is justified in Reference 18.

Consistent with the requirement in Reference 18 to include Tier 2 insights into the decision-making process before taking equipment out of service, restrictions on concurrent removal of certain equipment when a RTB train is inoperable for maintenance are included (note that these restrictions do not apply when a RTB train is being tested under the 4-hour bypass Note of Condition R). Entry into Condition R is not a typical, pre-planned evolution during power operation, other than for surveillance testing. Since Condition R is typically entered due to equipment failure, it follows that some of the following restrictions may not be met at the time of Condition R entry. If this situation were to occur during the 24-hour Completion Time of Required Action R.1, the Configuration Risk Management Program will assess the emergent condition and direct activities to restore the inoperable RTB train and exit Condition R or fully implement these restrictions or perform a plant shutdown, as appropriate from a risk management perspective.

The following restrictions will be observed:

The probability of failing to trip the reactor on demand will increase when a RTB train is removed from service, therefore, systems designed for mitigating an ATWS event should be maintained available. RCS pressure relief (pressurizer PORVs and safeties), auxiliary feedwater flow (for RCS heat removal), AMSAC, and turbine trip are important to alternate ATWS mitigation. Therefore, activities that degrade the availability of the auxiliary feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a RTB train is inoperable for maintenance.

Due to the increased dependence on the available reactor trip train when one logic train or one RTB train is inoperable for maintenance, activities that degrade other components of the RTS, including master relays or slave relays, and activities that cause analog channels to be unavailable, should not be scheduled when a logic train or a RTB train is inoperable for maintenance.

Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., essential service water) that support the systems or functions listed in the first two bullets should not be scheduled when a RTB train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

RTS Instrumentation B 3.3.1 BASES ACTIONS U.1 and U.2 (continued) inoperable trip mechanism to OPERABLE status, The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months for Required Action U.1 is reasonable considering that in this Condition there is one remaining diverse trip feature for the affected RTB, and one OPERABLE RTB capable of performing the safety function and given the low probability of an event occurring during this interval.

V.1 Not used.

W.1 and W.2 Condition W applies to the Trip Time Delay (TTD) circuitry enabled for the SG Water Level - Low Low trip Function when THERMAL POWER is less than or equal to 22.41% RTP in MODES 1 and 2. With one or more Vessel AT Equivalent (Power-1, Power-2) channel(s) inoperable, the associated Vessel AT channel(s) must be placed in the tripped condition 12 -within hours. If the inoperability impacts the Power-1 and Power-2 portions of the TTD circuitry (e.g., Vessel AT RTD failure), both the Power-1 and Power-2 bistables in the affected protection set(s) are placed in the tripped condition. However, if the inoperability is limited to either the Power-i or Power-2 portion of the TTD circuitry, only the corresponding Power-1 or Power-2 bistable in the affected protection set(s) is placed in the tripped condition. With one or more TTD circuitry delay timer(s) inoperable, both the Vessel AT (Power-1) and Vessel AT (Power-2) channels are tripped. This automatically enables a zero time delay for that protection channel with either the normal or adverse containment environment level bistable enabled. The Completion Time of 2

hours is based o Referenci If the inoperable channel cannot be placed in the trippe condition thin the specified Completion Time, the unit must be place in a MODE here this Function is not required to be OPERABLE. An a ditional si ours is allowed to place the unit in MODE 3.

11.

(continued)

CALLAWAY PLANT B 3.3.1-44 Revision 3

RTS Instrumentation B 3.3.1 p

BASES ACTIONS X.1 and X.2 (continued)

Condition X applies to the Environmental Allowan e Modifier (EAM) circuitry for the SG Water Level - Low ow trip Fu ction in MODES 1 and 2. With one or more EAM chann (s) inope ble, they must be placed in the tripped condition within hours I cing an EAM channel in trip automatically enables the SG Water Level - ow Low (Adverse 5 7zA e JeccUa

}

Containment Environment) bistable for that prot ction channel, with its 4 1hC41heted7L

+

higher SG level Trip Setpoint (a higher trip setp nt means a reactor trip

[\\ fle er h

would occur sooner). The Completion Time of hours is based on Reference6 If the inoperable channel cannot be placed in the tpped condition w4hin the specified Completion Time, the unit must be placed in a MODE w ere this Function is not required to be OPERABLE. An additional x hours is allowed to place the unit in MODE 3.

-7.

SURVEILLANCE The SRs for each RTS Function are identified by the SRs column of REQUkREMENTS Table 3.3.1-1 for that Function.

A Note has been added stating that Table 3.3.1-1 determines which SRs apply to which RTS Functions.

Note that each channel of process protection supplies both trains of the RTS. When testing Channel I, Train A and Train B must be examined.

Similarly, Train A and Train B must be examined when testing Channel II, Channel IlIl, and Channel IV. The CHANNEL CALIBRATIONs and COTs are performed in a manner that is consistent with the assumptions used in analytically calculating the required channel accuracies.

SR 3.3.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

(continued)

CALLAWAY PLANT B 3.3.1-45 Revision 3

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS SR 3.3.1.3 (continued) indication. Based on plant operating experience, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable time frame to limit operation above 50% RTP while completing the procedural steps associated with the surveillance in an orderly manner.

.I.

. I The Frequency of every 31 EFPD is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Also, the slow changes in neutron flux during the fuel cycle can be detected during this interval.

SR 3.3.1.4 6

SR 3.3.1.4 is the performance of a TADOT everysdays on a STAGGERED TEST BASIS. This test shall verify OPERABILITY by actuation of the end devices. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The RTB test shall include separate verification of the undervoltage and shunt trip mechanisms. Independent verification of RTB undervoltage and shunt trip Function is not required for the bypass breakers. No capability is provided for performing such,? test at power. The independent test for bypass breakers is included in SR 3.3.1.14. The bypass breaker test shall include a local manual shunt trip only. A Note has been added to indicate that this test must be performed on the bypass breaker prior to placing it in service.

62 The Frequency of everyddays on a STAGGERED TEST BASIS is SR 3.3.1.5 SR 3.3.1.5 is the perfo ance of an ACTUATION LOGIC TEST. The SSPS is tested every days on a STAGGERED TEST BASIS, using the semiautomatic tester. The train being tested is placed in the bypassed condition, thus preventing inadvertent actuation. Through the semiautomatic tester, all possible logic combinations, with and without (continued)

CALLAWAY PLANT B 3.3.1-49 Revision 3

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.5 (continued)

REQUIREMENTS applicable permissive, are tested for each protection function, including operation of the P-7 rmissive which is a-logic function only. The Frequency of every days on'a STAGGERED TEST BASIS is

,uay~~

lbas~e onddt~e~i~xewyo jzs~r~re A,l'erece 1?2.

.~~~~~~~~~~~ipf#

.. n SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels.

If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the incore detector measurements. If the excore channels cannot be adjusted, the channels are declared inoperable. This Surveillance is performed to verify the f(AI) input to the Overtemperature AT Function.'- Determination of the loop-specific vessel ATand T,,, values'sho'uld be made when performing this.

calibration, under steady state conditions (AT0 and 1' [" for Overpower.

AT] when at 100% RTP).

A Note modifies SR 3.3.1.6. The Note states that this Surveillance is required only if reactor power is 2 75% RTP and that 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after achieving equilibrium conditions with THERMAL POWER 2 75% RTP is allowed for performing the first surveillance. Equilibrium conditions are achieved when the core is sufficiently stable at intended operating conditions to perform flux mapping.

The SR is deferred until a scheduled testing plateau above 75% RTP is attained during a power ascension. During a typical power ascension, it is usually necessary to control the axial flux difference at lower power levels through control rod insertion. Afterequilibrium conditions are achieved at the specified power plateau, a flux map must be taken and the required data collected. The data is typically analyzed and the appropriate excore calibrations completed within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months after achieving equilibrium conditions. An additional time allowance of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is provided during which the effects of equipment failures may be remedied and any required re-testing may be performed.

The allowance of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after equilibrium conditions are attained at the testing plateau provides sufficient time to allow power ascensions and associated testing to be conducted in a controlled and orderly manner at conditions that provide acceptable results and without introducing the potential for extended operation at high power levels with instrumentation that has not been verified to be OPERABLE for subsequent use.

(continued)

CALLAWAY PLANT B 3.3.1-50 Revision 3

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.6 (continued)

REQUIREMENTS The.Frequency of 92 EFPD is adequate. It is based on industry operating

,experience, considering instrument reliability and operating history data for instrument drift.

-SR 3.3.1.7.

SR 3.3.1.7 is the-performance' of a COT every(days.

COT is perforned on each required channel to ensure the channel will perform the intended Function. A successful test of the required f contact(s) of a channel relay may be performed by the verification of the

.change of state of a single.contact of the relay. This clarifies what is an acceptable CHANNEL OPERATIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable

-extensions.

- Setpoints must be within the Allowable Values specified in Table 3.3.1-1.

SR 3.3.1.7 is modified by two Notes. Note 1 provides a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months delay in

,.the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the Applicability is exited and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in MODE 3 with the Rod Control System capable of rod withdrawal of one or more rods not fully inserted for > 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , this Surveillance must be performed prior to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entry into MODE 3. Note 2 requires that the quarterly COT for the source range instrumentation shall include verification by observation of the associated permissive annunciator window that the P-6 and P-10 interlocks'are in their required state for the existing unit conditions.

/ 1?+

The Frequency of6 days is justified in Referenced I?.

SR 3.3.1.8 SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7 and it is modified by the same Note that this test shall include verification that the P-6 and P-1 0 interlocks are in their required state for the existing unit conditions by observation of the associated permissive annunciator (continued)

CALLAWAY PLANT B 3.3.1-51 Revision 3

RTS Instrumentation B 3.3.1 BASES SURVEILLAI REQUIREME U

t. F CR 2 I f1 rlnlnssnA1 1*

It %-# LB I

uw mllu ELAo J

/

=_NTS A

O window. A successful t t of the required contact(s) of a channel relay may be performed by t e verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL OPERATIONAL TES of a relay. This is acceptable because all of the other required conta s of the relay are verified by other Technical Specifications and n n-Technical Specifications tests at least once per refueling interval with applicable extensions. The Frequency is modified by a Note that allo*

this surveillance to be satisfied if it has been performed withindpays of the Frequencies prior to reactor startup, 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-10, and four hours after reducing power below P-6, as discussed below.. The Frequency of "prior to reactor startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below P-6" (applicable to source range channel 184 allows a normal shutdown to be completed and the unit removed fyom the MODE of Applicability for this surveillance without a delay to pe~drm the testing required by this surveillance. The Frequency of every ~ days thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup, 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-1, and four hours after reducing power below P-6. The MODE of Applicability for this surveillance is < P-1 0 for the power range low and intermediate range channels and < P-6 for the source range channels. Once the unit is in MODE 3, this surveillance is no longer required. If power is to be maintained < P-10 for more than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or

< P-6 for more than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , then the-testing required by this surveillance must be performed prior to the expiration of the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limit, as applicable. These time limits are reasonable, based on operating experience, to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for the periods discussed above. 7 e

enc,

/4-gAJsA

&Oje A iefep-ce /P.

SR 3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 5. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical (continued)

CALLAWAY PLANT B 3.3.1-52 Revision 3

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.16 (continued)

REQUIREMENTS 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.3.1.16 is modified by a Note stating that neutron detectors are excluded from RTS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal.

Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. Response time of the neutron flux signal portion of the channel shall be verified from detector output or input to the first electronic component in the channel.

REFERENCES

1.

FSAR, Chapter 7.

2.

FSAR, Chapter 15.

3.

IEEE-279-1971.

4.

10 CFR 50.49.

5.

Callaway OL Amendment No. 17 dated September 8, 1986.

6.

Callaway Setpoint Methodology Report, SNP (UE)-565 dated May 1, 1984.

7.

Callaway OLAmendment No. 43 dated April 14, 1989.

8.

FSAR Section 16.3, Table 16.3-1.

9.

WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements," January 1996.

10.

FSAR Table 15.0-4.

11.

WCAP-9226, "Reactor Core Response to Excessive Secondary Steam Releases," Revision 1, January 1978.

12.

e eebee-

13.

FSAR Section 15.1.1.

14.

RFR - 18637A.

CALLAWAY PLANT B 3.3.1-59 Revision 4

RTS Instrumentation B 3.3.1 BASES REFERENCES (continued)

15.

WCAP-14036-P-A, Revision 1, Elimination of Periodic Protection Channel Response Time Tests," October 1998.

16.

FSAR Section 15.4.6.

--y-A1rser 5 CALLAWAY PLANT B 3.3.1-60

.Revision 4

INSERT 5

17.

WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998.

18.

WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003.

ESFAS Instrumentation B 3.3.2 BASES ACTIONS C.1, C.2, C.3.1. and C.3.2 (continued) one Phase A train is inoperable, operation may continue as long as the Required Action to place and maintain containment purge supply and exhaust valves in their closed position is met. Required Action C.1 is modified by a Note that this Action is only required if Containment Phase A Isolation (Function 3.a.(2)) is inoperable. If one train is 4

I noperable, hours are allowed to restore the train to OPERABLE status.

The specified Completion Time is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be restored to OPERABLE status, 6

the unit must be placed in a MODE in which the LCO does not apply.

This is done by placing the unit in at least MODE 3 within an additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (I2 hours total time) and in MODE 5 within an additional 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months 60 hours tjal time). The Completion Times are reasonable, based on operating xperience, to reach the required unit conditions from full power conditions n an orderly manner and without challenging unit systems.

30 The Required Actions are modified by a Note that allows one train to be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other train is OPERABLE. This allowance is based on the reliability analysis assumption of Reference 8 that 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is the average time required to perform2EEDtsurveillance.

xINJ,SE 6 A D.1, D.2.1, and D.2.2 Condition D applies to:

Containment Pressure - High 1; Pressurizer Pressure - Low; Steam Line Pressure - Low; Containment Pressure - High 2; Steam Line Pressure - Negative Rate - High; SG Water Level - Low Low (Adverse Containment Environment);

SG Water Level - Low Low (Normal Containment Environment);

and Pressurizer Pressure - High.

(continued)

CALLAWAY PLANT B 3.3.2-40 Revision 3

INSERT 6 The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed for restoring the inoperable train to OPERABLE status is justified in Reference 18.

INSERT6A Consistent with the requirement in Reference 18 to include Tier 2 insights into the decision-making process before taking equipment out of service, restrictions on concurrent removal of certain equipment when a logic train is inoperable for maintenance are included (note that these restrictions do not apply when a logic train is being tested under the 4-hour bypass Note of Condition C). Entry into Condition C is not a typical, pre-planned evolution during power operation, other than for surveillance testing. Since Condition C is typically entered due to equipment failure, it follows that some of the following restrictions may not be met at the time of Condition C entry. If this situation were to occur during the 24-hour Completion Time of Required Action C.2, the Configuration Risk Management Program will assess the emergent condition and direct activities to restore the inoperable logic train and exit Condition C or fully implement these restrictions or perform a plant shutdown, as appropriate from a risk management perspective.

The following restrictions will be observed:

To preserve ATWS mitigation capability, activities that degrade the availability of the auxiliary feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a logic train is inoperable for maintenance.

To preserve LOCA mitigation capability, one complete ECCS train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

To preserve reactor trip and safeguards actuation capability, activities that cause master relays or slave relays in the available train to be unavailable and activities that cause analog channels to be unavailable should not be scheduled when a logic train is inoperable for maintenance.

Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., essential service water and component cooling water) that support the systems or functions listed in the first three bullets should not be scheduled when a logic train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

ESFAS Instrumentation B 3.3.2 BASES ACTIONS D.1. D.2.1, and D.2.2 (continued)

If one channel is inoperable, Chors are allowed to restore the channel to OPERABLE status or to place it in the tripped condition. Generally this Condition applies to functions that operate on two-out-of-three logic (excluding Pressurizer Pressure - Low, Pressurizer Pressure - High, and SG Water Level - Low Low (Adverse and Normal Containment Environment)). Therefore, failure of one channel (i.e., with the bistable not tripped) places the Function in a two-out-of-two configuration. The inoperable channel must be tripped to place the Function in a one-out-of-two configuration that satisfies redundancy requirements

-ZWv-r,7-Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition withind hours requires the unit be placed in MODE 3 within the following 6 ours and MODE 4 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

t 7.2 The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, these Functions are no longer required OPERABLE.

The Required Actions are modifie by a Note that allows the inoperable channel to be bypassed for up to hours for surveillance testing of other channels.J [lto9dr bit rMe cpannqpto,0EiW ours allowed for testi~,Tare justified in ReferenceS /P.

-/-A e /;2 E.1, E.2.1. and E.2.2 Condition E applies to:

Containment Spray Containment Pressure - High 3; and Containment Phase B Isolation Containment Pressure - High 3.

None of these signals has input to a control function. Thus, two-out-of-three logic is necessary to meet acceptable protective requirements. However, a two-out-of-three design would require tripping a failed channel. This is undesirable because a single failure would then cause spurious containment spray initiation. Spurious spray actuation is undesirable because of the cleanup problems presented. Therefore, these channels are designed with two-out-of-four logic so that a failed channel may be bypassed rather than tripped. Note that one channel may be bypassed and still satisfy the single failure criterion. Furthermore, (continued)

CALLAWAY PLANT B 3.3.2-41 Revision 3

INSERT 7 The 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed to restore the channel to OPERABLE status or to place it in the tripped condition is justified in Reference 18.

ESFAS Instrumentation B 3.3.2 BASES ACTIONS E.1. E.2.1. and E.2.2 (continued) with one channel bypassed, a single instrumentation channel failure will not spuriously initiate containment spray.

7;1 To avoid the m adertent actuation of containment spray and Phase B containment isolion, the inoperable channel should not be placed in the tripped condition Instead it is bypassed. Restoring the channel to OPERABLE stat s, or placing the inoperable channel in the bypassed condition withint hours, is sufficient to assure that the Function remains OPERABLE and minimizes the time that the Function may be in a partial trip condition (assuming the inoperable channel has failed high). The Completion Time is further justified based on the low probability of an event occurring during this interval. Failure to restore the inoperable channel to OPERABLE status, or place it in the bypassed condition within 7:2 @hours, requires the unit be placed in MODE 3 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, these Functions are no longer required OPERABLE.

The Required Actions are modifie by a Note that allows one additional channel to be bypassed for up to hours for surveillare testing. Placing a second channel in the bypassed condition for up to hours for testing purposes is acceptable based on the results of Reference IA.

F.1, F.2.1. and F.2.2 Condition F applies to:

Manual Initiation of Steam Line Isolation; and P-4 Interlock.

For the Manual Initiation and the P4 Interlock Functions, this action addresses the train orientation of the SSPS. If a channel or train is inoperable, 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months are allowed to return it to OPERABLE status. The specified Completion lime is reasonable considering the nature of these Functions, the available redundancy, and the low probability of an event occurring during this interval. If the Function cannot be returned to OPERABLE status, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power in an orderly manner (continued)

CALLAWAY PLANT B 3.3.2-42 Revision 3

ESFAS Instrumentation B 3.3.2 BASES ACTIONS F.1. F.2.1. and F.2.2 (continued) and without challenging unit systems. In MODE 4, the unit does not have any analyzed transients or conditions that require the explicit use of the protection functions noted above.

G.1. G2.1, and G2.2 Condition G applies to the automatic actuation logic and actuation relays (SSPS) for the Steam Line Isolation, Turbine Trip and Feedwater Isolation, and AFW actuation Functions.

'I

~~~~~~~24-The action addresses the train orienton of the actuation logic for these functions. If one train is inoperable, hours are allowed to restore the train to OPERABLE status The Completion Time for restoring a train to CAI SE~r~

I~f OPERABLE status is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be returned to OPERABLE status, the unit must be brought to MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. Placing the unit in MODE 4 removes all requirements for OPERABILITY of the protection channels and actuation functions. In this MODE, the unit does not have analyzed transients or conditions that require the explicit use of the protection functions noted above.

The Required Actions are modified by a Note that allows one train to be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE. This allowance is based on the reliability analysis (

8) assumption that 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is the average time required to performi Sur surveillance.

H.1 Condition H applies to the automatic logic and actuation relays (SSPS) for the Automatic Pressurizer PORV Actuation Function.

The Required Action addresses the impact on the ability to mitigate an inadvertent ECCS actuation at power event that requires the availability of at least one pressurizer PORV for automatic pressure relief. With one or more automatic actuation logic trains inoperable, the associated pressurizer PORV(s) must be declared inoperable immediately. This (continued)

CALLAWAY PLANT B 3.3.2-43 Revision 3

INSERT 6 The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed for restoring the inoperable train to OPERABLE status is justified in Reference 18.

INSERT 6B Consistent with the requirement in Reference 18 to include Tier 2 insights into the decision-making process before taking equipment out of service, restrictions on concurrent removal of certain equipment when a logic train is inoperable for maintenance are included (note that these restrictions do not apply when a logic train is being tested under the 4-hour bypass Note of Condition G). Entry into Condition G is not a typical, pre-planned evolution during power operation, other than for surveillance testing. Since Condition G is typically entered due to equipment failure, it follows that some of the following restrictions may not be met at the time of Condition G entry. If this situation were to occur during the 24-hour Completion Time of Required Action G.1, the Configuration Risk Management Program will assess the emergent condition and direct activities to restore the inoperable logic train and exit Condition G or fully implement these restrictions or perform a plant shutdown, as appropriate from a risk management perspective.

The following restrictions will be observed:

To preserve ATWS mitigation capability, activities that degrade the availability of the auxiliary feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a logic train is inoperable for maintenance.

To preserve LOCA mitigation capability, one complete ECCS train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

To preserve reactor trip and safeguards actuation capability, activities that cause master relays or slave relays in the available train to be unavailable and activities that cause analog channels to be unavailable should not be scheduled when a logic train is inoperable for maintenance.

Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., essential service water and component cooling water) that support the systems or functions listed in the first three bullets should not be scheduled when a logic train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

ESFAS Instrumentation B 3.3.2 BASES ACTIONS H.1 (continued) requires that Condition B or E of LCO 3.4.11, "Pressurizer PORVs,' be entered immediately depending on the number of PORVs inoperable.

The Required Action is modified by a Note that allows one train to be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE. This allowance is based on the reliability analysis (Refs. 8 and 13) assumption that 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is the average time required to perform channel surveillance.

1.1 and 1.2 Condition I applies to:

SG Water Level - High High (P-14).

72t rat7 If one channel is inoperable, hours are allowed t restore the channel to OPERABLE status or to place it in the tripped condjtion. If placed in the tripped condition, the Function is then in a partial trip condition where

/ ~. one-out-of-three logic will result in actuation. The hour Completion lime Is justnied in References2 Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition withiitMour 7

requires the unit to be placed in MODE 3 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The allowed Completion Time ofd is reasonable, based on operating experience, to reach DODE 3 from full power conditions in an orderly manner and without ch lenging unit systems. In MODE 3, this Function is no longer required PEBABLE.,

The Required Actions are modified by a Note that allows the inoperable channel to be bypassed for up top hoursfor surveillance testing of other channels. Thee hours allowed to lace the inoperable channel in the tripped condition, and the hours llowed for an inoperable channel to be in the bypassed condition r testin, are justified in Referencedp Ir.

J.1 and J.2 Condition J applies to the AFW pump start on trip of all MFW pumps.

This action addresses the train orientation of the BOP ESFAS for the auto start function of the AFW System on loss of all MFW pumps. The OPERABILITY of the AFW System must be assured by providing automatic start of the AFW System pumps. If a channel is inoperable, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to place it in the tripped condition. If the channel cannot be tripped in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , 6 additional hours are allowed to place the unit in (continued)

CALLAWAY PLANT B 3.3.2-44 Revision 3

ESFAS Instrumentation B 3.3.2 BASES ACTIONS J.1 and J.2 (continued)

MODE 3. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. In MODE 3, the unit does not have any analyzed transients or conditions that require the explicit use of the protection function noted above. The Required Actions are modified by a Note that allows the inoperable channel to be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of other channels.

K.J.

Condition K applies to:

Fo #e -h-ieJI col;4i RWST Level - LqLw Coincident with Safety Injection.

RWST Level - Low Lo Coincident With SI provides actuation of switchover to the conta nment recirculation sumps. Note that this Function requires the stables to energize to perform their required action. The failure of up to two channels will not prevent the operation of this Function. This Ac on Statement limits the duration that an RWST level channel could be e

i ab s

(tifin order to limit the probability for automatic switchover to an empty containment sump upon receipt of an inadvertent safety injection signal (SIS), coincident with a single failure of another RWST level channel, or for premature switchover to the sump after a valid SIS. This sequence of events would start the RHR pumps, open the containment sump RHR suction valves and, after meeting the sump suction valve open position interlock, the RWST RHR suction valves would close. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months restoration time for an inoperable channel is consistent with that given in other Technical Specifications affecting RHR operability, e.g., for one ECCS train inoperable and for one diesel generator inoperable.

,,4^0

/

The Completion Times are justified in Referenc 8 f the channel cannot be w

IUn returned to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the unit must be brought to MODE 3 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 5, the unit does not have any analyzed transients or conditions that require the explicit use of the protection function noted above. The Required Actions are modified by a Note that allows placing an inoperable channel in the bypassed condition for up toolhours for surveillance testing of other channels. This bypass allowance is justified in -Mec /tcersre q,,sc4me 1Tt [fr?0 Knay References Ie.

L

/

(continued)

CALLAWAY PLANT B 3.3.2-45 Revision 3

ESFAS Instrumentation B 3.3.2 BASES ACTIONS L.1, L.2.1. and L.2.2 (continued)

Condition L applies to the P-11 interlock.

With one or more required channel(s) inoperable, the operator must verify that the interlock is in the required state for the existing unit condition by observation of the associated permissive annunciator window. This action manually accomplishes the function of the interlock. Determination must be made within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is equal to the time allowed by LCO 3.0.3 to initiate shutdown actions in the event of a complete loss of ESFAS function. If the interlock is not in the required state (or placed in the required state) for the existing unit condition, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. Placing the unit in MODE 4 removes all requirements for OPERABILITY of this interlock.

M.1 and M.2 Condition M applies to the Trip Time Delay (TTD) circuitry enabled for the SG Water Level-Low Low trip Functions when THERMAL POWER is less than or equal to 22.41% RTP in MODES 1 and 2. With one or more Vessel AT Equivalent (Power-1, Power-2) channel(s) inoperable, the associated Vessel AT channel(s) must be placed in the tripped condition wiihin hours. If the inoperability impacts the Power-1 and Power-2 portions of the TTD circuitry (e.g., Vessel AT RTD failure), both the Power-1 and Power-2 bistables in the affected protection set(s) are placed in the tripped condition. However, if the inoperability is limited to either the Power-1 or Power-2 portion of the TTD circuitry, only the corresponding Power-1 or Power-2 bistable in the affected protection set(s) is placed in the tripped condition. With one or more TTD circuity delay timer(s) inoperable, both the Vessel AT (Power-1) and Vessel AT (Power-2) channels are tripped. This automatically enables a zero time delay for that protection channel with either the normal or adverse containment environment level bistable enabled. The Completion Time of

-7;-ohours is based orReferences If the inoperable channel cannot be placed in the trippe condition w hin the specified Completion Time, the unit must be place in a MODE here this Function is not required to be OPERABLE. The nit must beklaced in MODE 3 within an additional six hours.

L /.

A,

/

'Cwe 41-eJ'C A egs (continued)

CALLAWAY PLANT B 3.3.2-46 Revision 3

ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)

N.1, N.2.1. and N.2.2 Condition N ap es o hhe Environm ntal Allowance Modifier (EAM) circuitry for th SG Water Level-Low ow trip Functions in MODES 1, 2, and 3. Witone or more EAM chann I(s) inoperable, they must be placed in e tripped condition within hours. Placing an EAM channel in trip auto atically enables the SG Water Level-Low Low (Adverse Contaitent Environment) bistable for that protection channel, with its highe SG level Trip Setpoint (a higher trip setpoint means a feedwater isol ion or an AFW actuation would occur sooner). The Completion Time of hours is based o eference If the inoperable channel cannot be placed in the tripped cndition withi the specified Completion Time, the unit must be placed in a MODE wh re this Function is not required to be OPERABLE. The uni must be pla d in MODE 3 within an additional six hours and in MODE within the flowing six hours.

I

-/~P.

0.1 and 0.2 L

Ae cereene ielet'4Ty/er~ti Condition 0 applies to the Auxiliary Feedwater Pump Suction Transfer on Suction Pressure - Low trip Function. The Condensate Storage Tank is the highly reliable and preferred suction source for the AFW pumps. This function has a two-out-of-three trip logic. Therefore, continued operation is allowed with one inoperable channel until the performance of the next monthly COT on one of the other channels, as long as the inoperable channel is placed in trip within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Condition 0 is modified by a Note stating that LCO 3.0.4 is not applicable. MODE changes are permitted with an inoperable channel.

P.I Condition P applies to the Auxiliary Feedwater Manual Initiation trip Function. The associated auxiliary feedwater pump(s) must be declared inoperable immediately when one or more channel(s) is inoperable.

Refer to LCO 3.7.5, "Auxiliary Feedwater (AFW) System."

Q.1 and Q.2 Condition Q applies to the Auxiliary Feedwater Balance of Plant ESFAS automatic actuation logic and actuation relays. With one train inoperable, the unit must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Required Actions are modified by a Note that allows one train to be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other train is OPERABLE.

(continued)

CALLAWAY PLANT B 3.3.2-47 Revision 3

ESFAS Instrumentation B 3.3.2 BASES ACTIONS R.1, R.2.1, and R.2.2 (continued)

Condition R applies to the Auxiliary Feedwater Loss of Offsite Power trip Function. With the inoperability of one or both train(s), 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months are allowed to return the train(s) to OPERABLE status. The specified

. Completion Time is reasonable considering this Function is only associated with the turbine driven auxiliary feedwater pump (TDAFP), the available redundancy provided by the motor driven auxiliary feedwater pumps, and the low probability of an event occurring during this interval.

If the Function cannot be returned to OPERABLE status, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power in an orderly manner and without challenging unit systems. In MODE 4, the unit does not have any analyzed transients or conditions that require the TDAFP for mitigation.

SURVEILLANCE The SRs for each ESFAS Function are identified by the SRs column of REQUIREMENTS Table 3.3.2-1.

A Note has been added to clarify that Table 3.3.2-1 determines which SRs apply to which ESFAS Functions.

Note that each channel of process protection supplies both trains of the ESFAS. When testing channel 1, train A and train B must be examined.

Similarly, train A and train B must be examined when testing channel 11, channel 1II, and channel IV. The CHANNEL CALIBRATION and COTs are performed in a manner that is consistent with the assumptions used in analytically calculating the required channel accuracies.

SR 3.3.2.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

(continued)

CALLAWAY PLANT B 3.3.2-4 8 Revision 2

INSERT 8 Condition S applies to the MSFIS automatic actuation logic and actuation relays.

The action addresses the train orientation of the actuation logic for these functions. If one train is inoperable, 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months are allowed to restore the train to OPERABLE status. The Completion Time for restoring a train to OPERABLE status is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be returned to OPERABLE status, the unit must be brought to MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. Placing the unit in MODE 4 removes all requirements for OPERABILITY of the protective function. In this MODE, the unit does not have analyzed transients or conditions that require the explicit use of the protection function noted above.

The Required Actions are modified by a Note that allows one train to be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE. This allowance is based on the reliability analysis (Reference 13) assumption that 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is the average time required to perform channel surveillance.

e -.@

A.

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE SR 3.3.2.1 (continued)

REQUIREMENTS Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including indication and reliability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside s limit.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

SR 3.3.2.2 q.

SR 3.3.2.2 is the perfogace of anA A ION LOGIC TEST. The SSPS is tested every days on a ST GGERED TEST BASIS, using the semiautomatic tester. The train being ested is placed in the bypassed condition, thus preventing inadvertent ctuation. Through the semiautomatic tester, all possible ogi combinations, with and without applicable permissives, are tested fo each protection function. In addition, the master relay coil is puls tested for continuity. This verifies that the logic modules are OPERAB E and that there is an intact voltage signal path to the master relay coils. na

ion, R i s the e ormance o an IC TEST of the FIS PLC actuation logic, initiated from the SSPS slave relays.

e Frequency of every 31 days on a STAGGERED TEST BASIS is ad quate. It is based on industry operating experience, considering instru ent reliability and

/

~oating history data.

s:3.,23 SR 3.3.2.3 SR 3.3.2.3 is the performance of an ACTUATION LOGIC TEST using the BOP ESFAS automatic tester. The continuity check does not have to be performed, as explained in the Note. This SR is applied to the balance of plant actuation logic and relays that do not have circuits installed to perform the continuity check. This test is required every 31 days on a STAGGERED TEST BASIS. The Frequency is adequate based on industry operating experience, considering instrument reliability and operating history data.

(continued)

CALLAWAY PLANT B 3.3.24 9 Revisiion 2

INSERT 9 The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 19.

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)

_X b5K ~J.Jq SR 3.3.2.4 is the rformance of a MASTER RELAY TEST. The MASTER RELAY ST is the energizing of the master. relay, verifying contact operation nd a low voltage continuity check of the slave relay coil. Upon master elay contact operation, a low voltage is injected to the slave relay coil.

is voltage is insufficient to pick up the slave relay, but large enough to d monstrate signal path continuity. This test is performed every days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 51JRtieustifie d

in Reference 8.

VNXJ

'/

SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.

A COT is performed on each required channel to ensure the channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3.2-1. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL OPERATIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The setpoint shall be left set consistent with the assumptions of the current unit specific setpoint methodology.

The Frequency oft)days is justified in Referenceg /9.

SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation mode is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment. Actuation equipment that may not be operated in the design mitigation mode is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay. This (continued)

CALLAWAY PLANT C LAAPLNB 3.3.2-50.

RRevision 2

INSERT 9 The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 19.

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE SR 3.3.2.6 (continued)

REQUIREMENTS test is performed every 92 days. The SR is modified by a Note tt excludes slave relays K602, K620, K622, K624, K630, K740, eK741 a.-1 k7s0o which are included in testing required by SR 3.3.2.13 and SR 3.3.2.14.

The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data.

SR 3.3.2.7 SR 3.3.2.7 is the performance of a TADOT every 18 months. This test is a check of the AFW pump start on Loss of Offsite Power trip Function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The trip actuating devices tested within the scope of SR 3.3.2.7 are the LSELS output relays and BOP ESFAS separation groups 1 and 4 logic associated with the automatic start of the turbine driven auxiliary feedwater pump on an ESF bus undervoltage condition.

The Frequency is adequate. It is based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints for relays. The trip actuating devices tested have no associated setpoint.

SR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions and AFW pump start on trip of all MFW pumps. The Manual Safety Injection TADOT shall independently verify OPERABILITY of the undervoltage and shunt trip handswitch contacts for both the Reactor Trip Breakers and Reactor Trip Bypass Breakers as well as the contacts for safety injection actuation. It is performed every 18 months. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The Frequency is adequate, based on industry operating (continued)

CALLAWAY PLANT B 3.3.2 Revision 2

ESFAS Instrumentation B 3.3.2 BASES REFERE (contint

NCES

11.

Callaway OLAmendment No.43 dated April 14, 1989.

jed)

12.

SLNRC 84-0038 dated February 27, 1984.

13.

Callaway OLAmendment No. 117 dated October 1, 1996.

14.

WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests," October 1998.

15.

FSAR, Section 15.5.1.

16.

FSAR, Section 15.6.1.

17.

Letter from Mel Gray (NRC) to Garry L. Randolph (UE),.ORevision 20 of the Inservice Testing Program for Callaway Plant, Unit 1 (TAC No. MA4469),* dated March 19,1999.

mA/J r

c I

CALLAWAY PLANT B 3.3.2-57 Revision 2

INSERT 10

18.

WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998.

19.

WCAP-1 5376-P-A, Revision 1, Risk-informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003.

BDMS B 3.3.9 BASES SURVEILLANCE SR 3.3.9.1 (continued)

REQUIREMENTS Agreement criteria are determined by the unit staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

SR 3.3.9.2 SR 3.3.9.2 requires that valve BGV0178 be secured and closed prior to entry into MODE 5. Specification 3.9.2 requires that this valve also be secured and closed in MODE 6. Closing BGV0178 satisfies the boron dilution accident analysis assumption that flow orifice BGFOO010 limits the dilution flow rate to no more than 150 gpm in MODE 5. This Surveillance demonstrates that the valve is closed through a system walkdown. SR 3.3.9.2 is modified by a Note stating that it is only required to be performed in MODE 5. This Note requires that the surveillance be performed prior to entry into MODE 5 and every 31 days while in MODE 5. The 31 day frequency is based on engineering judgment and is considered reasonable in view of other administrative controls that will ensure that the valve opening is an unlikely possibility.

SR 3.3.9.3

/4 SR 3.3.9.3 requires the performance of a COT every 6days, to ensure that each train of the BDMS and associated trip setpoints are fully operational. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL OPERATIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. This test shall include verification that the boron dilution flux multiplication setpoint is equal to or less than an increase of 1.7 times the count rate within a 10 minute period. The 1.7 flux multiplication setpoint is a nominal value. SR 3.3.9.3 is met if the measured setpoint is within a two-sided calibration tolerance band on either side of the nominal value. SR 3.3.9.3 is modified by a (continued)

CALLAWAY PLANT B 3.3.9-6 Revision 3

BDMS B 3.3.9 BASES SURVEILLANCE SR 3.3.9.3 (continued)

REQUIREMENTS Note that provides a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months delay in the requirement to perform this Surveillance after reducing power below the P-6 interlock. This Note allows a delay in the performance of the COT to reflect the delay allowed for the source range channels. If the plant is to remain below the P-6 setpoint for more than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , this Surveillance must be performed prior to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below the P-6 setpoint. The Frequency of

/j4-days is consistent with the requirements for source range channels in Reference 2.

SR 3.3.9.4 SR 3.3.9.4 is the performance of a CHANNEL CALIBRATION every 18 months. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy. The SR is modified by a Note that neutron detectors are excluded from the CHANNEL CALIBRATION. Neutron detectors are excluded from the CHANNEL CALIBRATION because it is impractical to set up a test that demonstrates and adjusts neutron detector response to known values of the parameter (neutron flux) that the channel monitors.

The Note applies to the source range proportional counters in the Nuclear Instrumentation System (NIS).

The testing of the source range neutron detectors consists of obtaining integral bias curves, evaluating those curves, and comparing the curves previous data. The 18 month Frequency is based on operating experience and on the need to obtain integral bias curves under the conditions that apply during a plant outage. The other remaining portions of the CHANNEL CALIBRATION may be performed either during a plant outage or during plant operation.

SR 3.3.9.5 SR 3.3.9.5 is the performance of a response time test every 18 months to verify that, on a simulated or actual boron dilution flux multiplication signal, the centrifugal charging pump suction valves from the RWST open and the CVCS volume control tank discharge valves close in the required time of 30 seconds to reflect the analysis requirements of Reference 1.

The Frequency is based on operating experience and consistency with the typical industry refueling cycle.

(continued)

CALLAWAY PLANT B 3.3.9-7 Revision 3

BDMS B 3.3.9 BASES SURVEILLANCE SR 3.3.9.6 REQUIREMENTS (continued)

SR 3.3.9.6 requires verification every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months that one RCS loop is in operation. Verification may include flow rate, temperature, or pump status monitoring, which help ensure that forced flow is providing adequate mixing. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient considering other indications and alarms available to the operator in the control room to monitor RCS loop performance.

REFERENCES

1.

FSAR, Section 15.4.6.

2.

Callaway OLAmendment No.

frh ngle m e 4fi WCA/9 Pevrjp

/,-

CALLAWAY PLANT B 3.3.9-8 Revision 3

ATTACHMENT 5

SUMMARY

OF REGULATORY COMMITMENTS

SUMMARY

OF REGULATORY COMMITMENTS The following table identifies those actions committed to by AmerenUE in this document. Any other statements in this submittal are provided for information purposes and are not considered to be commitments. Please direct questions regarding these commitments to Mr. Dave E. Shafer, Superintendent Licensing, (314) 554-3104.

COMMITMENT Due Date/Event The proposed changes to the Callaway Technical Within 90 days of Specifications will be implemented within 90 days of NRC NRC approval.

approval.

Activities that degrade the availability of the auxiliary Administrative feedwater system, RCS pressure relief system controls in place (pressurizer PORVs and safety valves), AMSAC, or within 90 days of turbine trip should not be scheduled when a logic train or NRC approval.

RTB train is inoperable for maintenance.

One complete ECCS train that can be actuated Administrative automatically must be maintained when a logic train is controls in place inoperable for maintenance.

within 90 days of NRC approval.

Activities that cause master relays or slave relays in the Administrative available train to be unavailable and activities that cause controls in place analog channels to be unavailable should not be within 90 days of scheduled when a logic train or RTB train is inoperable NRC approval.

for maintenance.

Activities on electrical systems (e.g., AC and DC power)

Administrative and cooling systems (e.g., essential service water and controls in place component cooling water (CCW only for an inoperable within 90 days of logic train)) that support the systems or functions listed NRC approval.

above should not be scheduled when a logic train or RTB train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

AmerenUE will trend as-found and as-left data under our Administrative System Health Program for the 3 representative trip controls in place functions analyzed in WCAP-1 5376 (i.e., OTDT, SG level, within 90 days of and pressurizer pressure) for two years (4 data points)

NRC approval.

after we implement the amendment granting 184-day COTs.

ATTACHMENT 6B TOPICAL REPORT APPLICABILITY DETERMINATION (NON-PROPRIETARY)

B Page 1 of 10 Safety Evaluation Condition 1 for WCAP-1 4333-P-A and WCAP-1 5376-P-A In order to address Safety Evaluation (SE) Condition 1 for both WCAPs, Westinghouse issued implementation guidelines for licensees to confirm the analyses are applicable to their plant.

Confirm Applicability

]ac Containment Failure Assessment

[

]a,c B

Page 2 of 10 Safety Evaluation Condition 4 for WCAP-1 5376-P-A

[

Iac B

Page 3 of 10 Table I WCAP-14333 Implementation Guidelines: Applicability of the Analysis General Parameters Parameter WCAP-14333 Analysis Plant Specific Parameter Assumptions Logic Cabinet Type (1)

SSPS or Relay SSPS Component Test Intervals (2)

Analog channels 3 months 3 months Logic cabinets (SSPS) 2 months 2 months Logic cabinets (Relay) 1 month NA Master Relays (SSPS) 2 months 2 months Master Relays (Relay) 1 month NA Slave Relays 3 months 3 months (11)

Reactor trip breakers 2 months 2 months Analog Channel Calibrations (3)

Done at-power l

Yes No (12)

Interval l

18 months 18 months Typical At-Power Maintenance Intervals (4)

Analog channels 24 months

> 24 months (13)

Logic cabinets (SSPS) 18 months

> 18 months (13)

Logic cabinets (Relay) 12 months NA Master relays (SSPS)

Infrequent (5)

Infrequent Master relays (Relay)

Infrequent (5)

NA Slave relays Infrequent (5)

Infrequent Reactor trip breakers 12 months 18 months B

Page 4 of 10 Table I WCAP-14333 Implementation Guidelines: Applicability of the Analysis General Parameters Parameter WCAP-14333 Analysis Plant Specific Parameter Assumptions AMSAC (6)

Credited for AFW pump start Credited for AFW pump start Total Transient Event Frequency (7) 3.6/year 2.03/year ATWS Contribution to CDF (current PRA model) (8) 8.4E-06/year 3.36E-07/year Total CDF from Internal Events (current PRA model) (9) 5.8E-05/year 3.09E-05/year Total CDF from Internal Events (PE) (10)

Not Applicable 5.85E-05/year (14)

NOTES FOR TABLE 1

1.

Both types of logic cabinets, SSPS and Relay, are included in WCAP-14333 and the analysis is applicable to Callaway.

2.

Since our test intervals are equal to or greater than those used in WCAP-14333, the analysis is applicable to Callaway.

3.

Since channel calibrations are not typically done at-power (see Note 12) and the calibration interval is equal to or greater than that used in WCAP-14333, the analysis is applicable to Callaway.

4.

Since our maintenance intervals are equal to or greater than those used in WCAP-14333, the analysis is applicable to Callaway.

5.

Only corrective maintenance is done on the master and slave relays. The typical maintenance interval is relatively long; that is, experience has shown they do not typically completely fail. Failure of these relays usually involves failure of individual contacts. Since "infrequent' master and slave relay failures are the norm, the WCAP-14333 analysis is applicable to Callaway.

6.

Since AMSAC will initiate AFW pump start, the WCAP-14333 analysis is applicable to Callaway.

7.

This entry includes the total frequency for initiators requiring a reactor trip signal to be generated for event mitigation to assess the importance of ATWS events to CDF. Events initiated by a reactor trip are not included. Since the plant specific value is less than the WCAP-14333 value, this analysis is applicable to Callaway.

8.

This entry indicates the ATWS contribution to core damage frequency (from at-power, internal events) to determine if the ATWS event is a large contributor to CDF.

9.

This entry indicates the total CDF from internal events (including internal flooding) for the most recent PRA model update for comparison to the NRC's risk-informed CDF acceptance guidelines.

10.

This entry indicates the total CDF from internal events from the IPE model submitted to the NRC in response to Generic Letter 88-20. See Note 14 for differences between the most recent PRA model update and that included in the GL 88-20 response.

11.

Except slave relays K602, K620, K622, K624, K630, K740, K741, and K750 which are tested every 18 months per SR 3.3.2.13 and SR 3.3.2.14.

12.

Analog channel calibrations are typically performed during refueling outages, but there is no requirement for that and they are sometimes performed at power.

B Page 5 of 10 NOTES FOR TABLE I

13.

Note 4 says WCAP-14333 applies if the maintenance intervals are greater than or equal to those assumed. Per Westinghouse, the note only applies to maintenance at power. Since we typically perform preventive maintenance on the analog channels, logic trains, and RTBs while shutdown, Callaway is covered.

14.

Note 10 requires reconciliation between the current CDF and that reported to NRC in response to GL 88-20. The 47% reduction between the current PRA model CDF and that reported in the IPE (i.e., IPE-reported CDF minus current CDF divided by IPE-reported CDF) is comprised of approximately a 20% reduction in internal flooding initiated CDF and approximately a 27% reduction in non-flooding CDF.

The reduction in the flooding initiated CDF is primarily due to: (1) a reduction in selected flood initiator frequencies; (2) actual calculation of the conditional core damage probability (CCDP), given a flood, as opposed to assuming a CCDP of 1.0; and (3) credit for the replacement of the positive displacement pump with the normal charging pump (NCP). The reduction in the non-flooding initiated CDF is primarily due to: (1) lower initiating event frequencies; (2) lower test/maintenance probabilities (i.e., shorter time duration that trains of equipment were in test or maintenance; (3) credit taken for the NCP; and (4) a change in the Service Water fault tree.

Table 2 WCAP-15376 Implementation Guidelines:

Applicability of the Analysis General Parameters B Page 6 of 10 a,c B

Page 7 of 10 Table 2 (Continued)

WCAP-15376 ImplementatIon Guidelines:

Applicability of the Analysis General Parameters WCAP-15376 Analysis Parameter Assumption (Plant) Specific Parameter ac B

Page 8 of 10 Table 3 WCAP-14333 and WCAP-15376 Implementation Guidelines:

Applicability of Analysis Reactor Trip Actuation Signals ac

.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

.9.

4

+

4 4

4

.9.

+

4 4

4 4~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

.4 4

4

-9.

.9.

B Page 9 of 10 Table 4 WCAP-14333 and WCAP-15376 Implementation Guidelines:

Applicability of Analysis Engineered Safety Features Actuation Signals I

I II I

I B

Page 10 of 10 Table 5 WCAP-15376 Implementation Guidelines:

Applicability of the Human Reliability Analysis a,c I1 i

4 4

I 4

ATTACHMENT 6C TOPICAL REPORT APPLICABILITY DETERMINATION PROPRIETARY AFFIDAVIT

Westinghouse Westinghouse Electric Company Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Direct tel:

Direct fax:

e-mail:

(412) 374-5036 (412) 3744011 galemIjs@westinghouse.com Our ref: CAW 1748 December 3, 2003 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

WCAP-15376 Implementation Guidelines Approach to Address the Conditions and Limitations in the NRC's Safety Evaluation (Proprietary)

The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-03-1748 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.790 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying affidavit by AmerenUE.

Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-03-1748, and should be addressed to the undersigned.

Very truly yours, J. S. Galembush, Acting Manager Regulatory Compliance and Plant Licensing Enclosures cc: D. Holland B. Benney E. Peyton A BNFL Group company

CAW-03-1748 bcc: J. S. Galembush (ECE 4-7A) IL R. Bastien, IL, IA (Nivelles, Belgium)

C. Brinkman, IL, IA (Westinghouse Electric Co., 2300Twinbrook Parkway, Suite 330, Rockville, MD 20852)

RCPL Administrative Aide (ECE 4-7A) (letter and affidavit only)

A BNFL Group company

CAW-03-1748 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

s COUNTY OF ALLEGHENY:

Before me, the undersigned authority, personally appeared J. S. Galembush, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:

J. S. Galembush, Acting Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this L1 day of 2003 Notary Public Noba Sew Shamn L Plod, Noaty Putic M

eBoro MAheny County Membe,.

Pemsyria AssoCaun Of Notanes

2 CAW-03-1748 (1)

I am Acting Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld fromi public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.

(2)

I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.790 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit.

(3)

I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

(4)

Pursuant to the provisions of paragraph (b)(4) of Section 2.790 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.

(i)

The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.

(ii)

The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.

Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a)

The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of

3 CAW 1748 Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

(b)

It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.

(c)

Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(d)

It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.

(e)

It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.

(f)

It contains patentable ideas, for which patent protection may be desirable.

There are sound policy reasons behind the Westinghouse system which include the following:

(a)

The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.

(b)

It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.

(c)

Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense.

4 CAW-03-1748 (d)

Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.

(e)

Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries.

(f)

The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.

(iii)

The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.790, it is to be received in confidence by the Commission.

(iv)

The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief.

(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in WCAP-15376 Implementation Guidelines Approach to Address the Conditions and Limitations in the NRC's Safety Evaluation on behalf of the Westinghouse Owners Group by Westinghouse, being transmitted by the Westinghouse Owners Group letter and Application for Withholding Proprietary Information from Public Disclosure to the Document Control Desk. The proprietary information as submitted for use by the Westinghouse Owners Group is applicable to other licensee submittals.

This information is part of that which will enable Westinghouse to:

5 CAW 1748 (a) Provide risk-informed assessment of the RTS and ESFAS to extend the interval for surveillance testing.

(b) Provide licensing defense services.

Further this information has substantial commercial value as follows:

(a)

Westinghouse plans to sell the use of similar information to its customers for purposes of extending surveillance testing intervals (b)

Westinghouse can sell support and defense of extending surveillance testing intervals.

Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar assessments and licensing defense services for commercial power reactors without commensurate expenses. Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.

In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.

Further the deponent sayeth not.

PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.

In order to conform to the requirements of 10 CFR 2.790 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the-information that was contained within the brackets in the proprietary versions having been deleted). The justification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a) through (4)(ii)(f) of the affidavit accompanying this transmittal pursuant to 10 CFR 2.790(b)(1).

._- 1, COPYRIGHT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.790 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose. Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.

ULNRC-04929, Common Stars License Amendment Regarding Implementation of WCAP-14333 and WCAP-15379, RTS and ESFAS Test Times, Completion Times, and Surveillance Test Intervals

Contents

Text

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

SUMMARY

SUMMARY

Subject:

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ULNRC-04929, Common Stars License Amendment Regarding Implementation of WCAP-14333 and WCAP-15379, RTS and ESFAS Test Times, Completion Times, and Surveillance Test Intervals

Text

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

SUMMARY

SUMMARY

Subject:

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