ML20195J849

Application for Amend to License DPR-28,increasing Stis, Adding Allowable OOS Times,Replacing Generic ECCS Actions for Inoperable Instrument Channels with function-specific Actions & Relocating Selected Trip Functions from TS

ML20195J849
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	06/15/1999
From:	Wanczyk R VERMONT YANKEE NUCLEAR POWER CORP.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
Shared Package
ML20195J855	List: ML20195J849 ML20195J869
References
BVY-99-76, NUDOCS 9906210141
Download: ML20195J849 (22)

Text

'

VERMONT YANKEE y NUCLEAR POWER CORPORATION 185 Old Ferry Road, Brattleboro, VT 05301 7002 (802) 257-5271 June 15,1999 BVY 99 76 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk 1 Washington, DC 20555'

)

l

Subject:

Vermont Yankee Nuclear Power Station  !

License No. DPR-28 (Docket No. 50-271) j Technical Specification Proposed Change No. 217 Surveillance Test Interval (STD and Allowable out-of-service Time (AOT)

Pursuant to 10CFR50.90, Vermont Yankee (VY) hereby proposes to amend its Facility Operating License, DPR-28, by incorporating the attached proposed change into the VY Technical Specifications.

This proposed change represents revisions to Technical Specifications Sections 3.1/4.1 Reactor Protection System and 3.2/4.2 Protective Instrument Systems instrumentation, tables, and the associated bases to increase the surveillance test intervals (STis), add allowable out-of-service times (AOTs),

replace generic ECCS actions for inoperable instrument channels with function-specific actions, and relocate selected trip functions from the Technical Specifications to a VY controlled document. In addition, revision to TS Sections 3.1/4.1 Reactor Protection System and the associated bases is being proposed to remove the RUN Mode APRM Downscale/IRM High Flux / Inoperative Scram Trip Function (APRM Downscale RUN Mode SCRAM). This submittal also proposes to implement editorial corrections and administrative changes that do not alter the meaning or intent of the requirements. The proposed TS changes were developed using General Electric (GE) Company Licensing Topical Reports (LTRs), GE design requirements and the guidance of the improved Standard Technical Specifications (STS), NUREG 1433, " Standard Technical Specification General Electric Plants, BWR/4," Revision 1.

This proposed change, if approved, will enhance operational safety by reducing 1) the potential for inadvertent plant scrams,2) excessive test cycles on equipment, and 3) the diversion of plant personnel and resources on unnecessary testing.

Attachment I to this letter contains description of changes, supporting information and the safety assessment of the proposed change. Attachment 2 contains the determination of no signincant hazards consideration. Attachment 3 provides the marked-up version of the current Technical Specification pages. Attachment 4 is the retyped Technical Specification pages.

VY has reviewed the proposed Technical Specification change in accordance with 10CFR50.92 and concludes that the proposed change does not involve a significant hazards consideration, 90)

VY has also reviewed the proposed change against the criteria of 10CFR51.22 for environmental l

considerations and concludes that the proposed change will not increase the types and amounts of effluents that may be released offsite. Thus, VY believes that the proposed change is eligible for 9906210141 990615 PDR ADOCK 050002 1 P -

I I VLHmm t YANut Nrca Au Powrn Com on.u uss categorical exclusion from the requirements for an environmental impact statement in accordance with j 10CFR51.22(c)(9).  !

l We request that the Staffissue the subject license amendment which will be effective upon issuance and implemented within 90 days of issuance. This latitude permits appropriate procedural and program revisions and training necessary to implement the proposed change.

Technical Specifications page 55 does not reflect changes submitted in Proposed Change No. 208, dated February 1,1999.

l If you have any questions on this transmittal, please contact Mr. Thomas B. Silko at (802) 258-4146.

Sincerely, I l

VERMONT YANKEE NUCLEAR POWER CORPORATION l Robert J. Wa c (///

Director of S and Regulatory Affairs STATE OF VERMONT 4 p,, SA

)

WINDHAM COUNTY

)ss

)

• [ NOTAR) l Then personally appeared before me, Robert J. Wanczyk, who, being duly sworn, did s a e ifggggor Safety and Regulators Affairs of Vermont Yankee Nuclear Power Corporation, that he is uth d to exe e and file the foregoing document in the name and on the behalf of Vermont Yankee Nuclear Co , an that the statements therein are true to the best of his knowledge and belief.

00U W

• Ia4 0 d k.----

Sally A. S/ndstrum, Notary Public My Commission Expires February 10,2003 Attachments l

cc: USNRC Region 1 Administrator USNRC Resident Inspector- VYNPS USNRC Project Manager- VYNPS Vermont Department of Public Service i

I 1

I I

l l

vr.nuosi v.whi.i. Ni ci.itait rowi-:ii coiu oit.viins Docket No. 50-271 BVY 99 76 i

I

{

Attachment i Vermont Yankee Nuclear Power Station Proposed Technical Specification Change No. 217 Surveillance Test Interval (STI) and Allowable out-of-service Time (AOT)

Supporting Information and Safety Assessment of Proposed Change

"""" " N CC " " l'o w tn C oni ou u n m j BVY 99-76 / Attachment I / Pag 91 INTRODUCTION The proposed technical changes reflect those standard Technical Specification revisions contained in the GE LTRs which, based upon probabilistic analyses, justify the identified time extensions by reducing:

i)potectial unnecessary plant scrams, ii) excessive equipment test cycles, and iii) the diversion of personnel and resources on unnecessary testing. The Staff has reviewed and approved these Licensing Topical Reports in the letters, and accompanying Safety Evaluation Reports (SERs), from A. C. Thadani (NRC) to T. A. Pickens (BWR Owners' Group) dated July 15, 1987; from Charles E. Rossi (NRC) to D. N. Grace (BWR Owners' Group) dated January 6,1989; from Charles E. Rossi (NRC) to S. D. Floyd (BWR Owners' Group) dated June 18,1990; from A. C. Thadani (NRC) to D. N. Grace (BWR Owners' Group) dated December 9,1988; from Charles E. Rossi (NRC) to D. N. Grace (BWR Owners' Group) dated December 9,1988; from Charles E. Rossi (NRC) to D. N. Grace (BWR Owners' Group) dated September 22,1988; Charles E. Rossi (NRC) to R. D. Binz IV (BWR Owners' Group) dated July 21, 1992; and Charles E. Rossi (NRC) to G. J. Beck (BWR Owners' Group) dated September 13,1991.

In addition, the RUN Mode APRM Downscale/lRM High Flux / Inoperative Scram Trip Function (APRM Downscale RUN Mode SCRAM) existed on several early BWR plants including VY. It was deleted by GE on later BWRs because it was not seen to be performing a function commensurate with i quired z surveillance, in consideration of this surveillance difficulty, and the doubtful contribution wnich was j made to the overall neutron monitoring protection system, GE decided to eliminate the APRM l Downscale RUN Mode SCRAM on later plants. GE has performed an evaluation specific to VY and has concluded it is a logical step to remove the requirement for this scram function from Technical Specifications (TS), consistent with the action taken at other contemporary plants.

The proposed amendment is designed to enhance safety using appropriate GE design requirements pertaining to neutron monitoring and adopting appropriate improved Standard Technical Specifications (STS), NUREG 1433, " Standard Technical Specification General Electric Plants, BWR/4," Revision 1 including relocation of selected instrumentation.

DESCRIPTION OF THE PROPOSED CHANGES .

l Revise the Reactor Protection System (SCRAM), Isolation Actuation, ECCS Actuation, Control Rod  !

Block and Selected Instrumentation Specification (TS Sections 3.1/4.1 and 3.2/4.2) regarding the j i

surveillance test intervals (STIs) and allowable out-of service times (AOTs) in accordance with GE LTRs NEDC-30851P-A dated March 1988, NEDC-30851P-A (Supplement 2) dated March 1989, NEDC-31677P-A dated July 1990, NEDC-30936P-A (Parts 1 and 2) dated December 1988, NEDC- 1 30851P-A (Supplement 1) dated October 1988, GENE-770-06-1 dated February 1991 and GENE-770-06-2 dated February 1991. Also, revise TS 3.1 to delete the APRM Downscale RUN Mode SCRAM,  !

implement editorial corrections and administrative changes, TS 3.2 to implement ECCS function-specific AOTs and actions and relocate selected instrumentation. The following changes are requested:

NEDC-30851P-A dated March 1988 / NUREG 1433 Revision 1

1. Revise note (2), to include allowable out-of-service times for specified Reactor Protection System (SCRAM) for required surveillance or repair. Correct an editorial error replacing

" condition" with " ACTION" and administrative change using upper case for ACTION. (TS TABLE 3.1.1 and TABLE 3.1.1 NOTES)

Vrauosi YAMLE NrcLEAn Powru Cosmotuuos BVY 99-76 / Anachment I / Page 2 -

2. Increase the Instrument Channel Test interval requirement specified in TS TABLE 4.1.1 from weekly or monthly to quarterly (every three months) and delete TABLE 4.1.1 NOTES footnote (1) for the following Trip Functions:

a. APRM -Trip Function 4.

b. High Reactor Pressure - Trip Function 5.

c. High Drywell Pressure - Trip Function 6.

d. Low Reactor Water Level- Trip Function 7.

c. High Water Level in Scram Discharge Volume - Trip Function 8.

f. High Main Steam Line Radiation - Trip Function 9.

g. Main Steam Line Iso. Valve Closure - Trip Function 10.

h. Turbine Control Valve Fast Closure - Trip Function 11.

i. Turbine Stop Valve Closure - Trip Function 12.

3. Revise footnote (8) to delete reference to monthly test program. Add footnote (9) to Scram Test Switch to perform weekly testing of the auto-scram contactors. (TS TABLE 4.1.1 and TABLE 4.1.1 NOTES)

APRM Downscale SCRAM

4. Delete the RUN Mode requirement for IRM High Flux / Inoperative and associated table note (11) for Trip Function 3. Delete the APRM Downscale in Trip Function 4. Add "X" for APRM INOP in startup as an editorial correction. (TS TABLE 3.1.1, TS TABLE 3.1.1 NOTES, and TS TABLE 4.1.1)

5. Add new Note (7) High Flux APRM Output Signal (Reduced) to perform overlap surveillance for SRM/lRM/APRM. (TS TABLE 4.1.2 and TS TABLE 4.1.2 NOTES)

NEDC-30936P-A (Parts 1 and 2) dated December 1988 / GENE-770-06-1 dated February 1991/

NUREG 1433 Revision 1

6. Add new notes (8) and (9), which includes allowable out-of-service times for specified EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION for required surveillance testing. Replace " Action" with " ACTION" as an administrative change. (TS TABLE 3.2.1 and TABLE 3.2.1 NOTES)

7. Add new notes (10), (11), (12), (13), (14), (15), (16), (17), (18) and (19) which includes selected function-specific allowable out-of-service times and actions for specified EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION. (TS TABLE 3.2.1 and TABLE 3.2.1 NOTES)

8. Delete the Bus Power Monitor for HPCI and ADS and associated actions. (TS TABLE 3.2.1 and TS T \BLE 4.2.1)

9. Iu *ht istrument Functional Test interval requirement in TS TABLE 4.2.1 from monthly is erly ad delete Note (1)in TABLE 4.2 NOTES for the following Trip Functions:

Core St avstem

a. High Drywell Pressure l

"""" YMEE NECI E su Powtu Com onu nn-L BVY 99-76 / Attachment I / Page 3 l

l. b. Low-Low Reactor Vessel Water Level

c. Low Reactor Pressure

d. . Low Reactor Pressure

e. Pump Discharge Pressure

f. Auxiliary Power Monitor

g. Pump Bus Power Monitor Low Pressure Coolina Iniection System

a. Low Reactor Pressure

b. High Drywell Pressure

c. Low-Low Reactor Vessel Water Level

d. . Reactor Vessel Shroud Level i e. ' Low Reactor Pressure l f. RHR Pump Discharge Pressure

g. High Drywell Pressure i

h. Low Reactor Pressure I'

i. Auxiliary Power Monitor

j. Pump Bus Power Monitor l High Pressure Coolant Iniection System I

a. Low-Low Reactor Vessel Water Level

b. Low Condensate Storage Tank Water Level

c. High Drywell Pressure

d. High Reactor Vessel Water Level Automatic Deoressurization System

a. Low-Low Reactor Vessel Water Level'

b. High Drywell Pressure ,

i Recirculation Pumo Trio Actuation

a. Low-Low Reactor Vessel Water Level

b. High Reactor Pressure NEDC-31677P-A dated July 1990 / NEDC-30851P-A Supplement 2 dated March 1991/ NUREG 1433 Revision 1

10. Add notes (11 and 12), which include allowable out-of-service times for specified Isolation Trip Functions for required surveillance or repair. Restore Note (3) to HPCI System Isolation -

Instrumentation in the ACTION column for the Trip System Logic and delete Note (2) on RCIC l - System Isolation Instrumentation Table in the Required Action column as an editorial correction.

l Replace " Action" with " ACTION" as an administrative change. (TS TABLE 3.2.2 and TABLE 3.2.2 NOTES)

11. Delete the Bus Power Monitor for HPCI, RCIC, and associated actions. (TS TABLE 3.2.2 and

- TS TABLE 4.2.2) i L

l

VI;H%loNI YA%I'I'. Nt ri.i:.An Pownsit Coni >oitxtioN BVY 99-76 / Attachment I / Page 4 -

12. Increase the Instrument Channel Test interval requirement in TS TABLE 4.2.2 from monthly to quarterly and delete note (1) in TABLE 4.2 NOTES for the following Trip Functions:

PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION

a. Low-Low Reactor Vessel Water Level

~ b. High Steam Line Area temperature

c. High Steam Line Flow

d. Low Main Steam Line Pressure

e. Low Reactor Vessel Water Level

f. High Main Steam Line Radiation

g. High Drywell Pressure

h. Condenser Low Vacuum HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION INSTRUMENTATION

a. High Steam line Space Temperature

b. High Steam Line D/P (Steam Line Break)

c. Low HPCI Steam Supply Pressure

d. Main Steam Line Tunnel Temperature REACTOR _ CORE ISOLATION COOLING SYSTEM ISOLATION INSTRUMENTATION

a. Main Steam Line Tunnel temperature

b. High Steam Line Space Temperature

c. High Steam Line d/p including time delay relays (Steam Line Break)

d. Low RCIC Steam Supply Pressure

13. Move note (1) from TS TABLE 3.2.3 and delete 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and add note (2) and note (3) allowable out-of service times for specified Isolation Trip Functions for required surveillance to new page titled TS TABLE 3.2.3 NOTES. Replace " Action" with " ACTION" as an administrative change. (TS TABLE 3.2.3)

14. Delete the Logic Bus Power Monitor for Reactor Building Ventilation Isolation and Standby Gas Treatment System Initiation and associated actions. (TS TABLE 3.2.3 and TS TABLE 4.2.3)

15. Increase the Instrument Channel Test interval requirement in TS TABLE 4.2.3 from monthly to quarterly and delete Note (1) in TABLE 4.2 NOTES for the following Trip Functions:

REACTOR BUILDING VENTILATION AND STANDBY GAS TREATMENT SYSTEM j ISOLATIOE l

a. Low Reactor Vessel Water Level

b. High Drywell Pressure

c. Reactor Building Vent Exhaust Radiation

d. Refueling Floor Zone Radiation

"N ^N .%uru Pows n Couron3ms BVY 99-76 / Attachment 1/ Page 5 l

NEDC-30851P-A Supplement I dated October 1988 / GENE-770-06-1 dated February 1991

16. Delete note (6) and add notes (10) and (11), which includes allowable out-of service times for i specified CONTROL ROD BLOCK Trip Functions for required surveillance. (TS TABLE 3.2.5 and TS TABLE 3.2.5 NOTES)

17. Increase the Instrument Channel Test interval requirement in TS TABLE 4.2.5 from monthly to quarterly and delete Note (1) in TABLE 4.2 NOTES for the following Trip Functions:

Average Power rance Monitor / Rod Block Monitor

a. Upscale (Flow Bias)

b. Downscale GENE-770-06-1 dated February 1991/ NUREG 1433 Revision I l

18. Add note (8), which includes allowable out-of-service times for specified POST-ACCIDENT i INSTRUMENTATION Parameters for required surveillance. (TS TABLE 3.2.6)

GENE-770-06-2-A dated February 1991/ NUREG 1433 Revision 1

19. Add notes (5), (6), (7), (8) and (9), which includes allowable out-of-service times and function specific actions for specified Reactor Core Isolation Cooling System Actuation Instrumentation Trip Functions for required surveillance or repair. Replace " Action" with " ACTION" as an administrative change. (TS TABLE 3.2.9 and TS TABLE 3.2.9 NOTES)

20. Delete the Bus Power Monitor for Reactor Core isolation Cooling System Actuation Instrumentation and associated action. (TS TABLE 3.2.9 and TS TABLE 4.2.9) i

21. Increase the Instrument Channel Test interval requirement in TS TABLE 4.2.9 from monthly to quarterly and delete note (1) in TABLE 4.2 NOTES for the following Trip Functions:

a. Low-Low Reactor Vessel Water Level

b. Low Condensate Storage Tank Water Level

c. High Reactor Vessel Water Level All of the Subject Licensing Topical Reports

22. Modify BASES 3.1/4.1 REACTOR PROTECTION SYSTEM and 4.2 PROTECTIVE SYSTEM to reference the GE Topical Reports, which justify the above-proposed changes, delete outdated FSAR supplement information, and add neutron monitoring overlap surveillance bases.

SAFETY ASSESSMENT The preface to NUREG 1433 describes the development of the improved Standard Technical ,

Specifications (STS) for General Electric (GE) BWR/4 plants. This NUREG is the result of extensive public technical meetings and discussions between the Staff and nuclear power plant licensees, nuclear steam supply system (NSSS) owners' groups, specifically the GE Owners' Group, and the Nuclear l

L _

j if VI:llMoNT YAntin NrcarAu Powru Colu>oitxtioN L( .BVY 99-76 / Attachm:nt I / Page 6 Energy Institute (NEI). Vermont Yankee (VY) proposes to adopt related requirements, as applicable to .

the licensing basis of the facility, to achieve a high degree of standardization and consistency.

These proposed TS changes are consistent with the above recommendations and applicable to VY licensing basis. Minor word additions / differences from STS are required to provide consistency with current 'IS wording and support the current licensing basis. These minor word additions / differences do not alter the meaning of STS instrumentation requirements or change the current licensing basis.

Exceptions to STS pri nciples were necessary to meet the current licensing basis and current format of existing TS. Editorial corrections and administrative changes do not alter the meaning or intent of any requirements.

l As a member of the BWR Owners' Group, we have extended the generic analyses completed by the l

BWR Owners' Group by completing the required plant-specific analyses and reposts. The following discussion provides the information required by the Staff in plant-specific submittals and Attachment 2 contains the determination of no significant hazards consideration completed pursuant to 10CFR50.92.

As stated within the Staffs SERs for the LTRs, three issues for NEDC-30851P-A and two issues for the other LTRs must be addressed to justify the applicability of the generic analyses to individual plants when specific facility technical specifications are considered for revision. The following is a discussion j of those issues: )

+ Confirm the applicability of the generic analyses to the specific facility. (This issue applies to all LTRs)

RESPONSE l l

Licensing Topical Report NEDC-30851P-A, Appendit L identifies VY, a BWR4, as a participating utility in the development of the RPS (SCRAM) Technical Specification improvement Analysis.

Section 7.4, " Conclusions of Plant Specific Applications," specifies that:

"The evaluation found various differences between the RPS configuration of various plants and the generic plant. These differences include HFA relays, four scram contactors for BWR/2, sensor differences, scram parameter differences, and SDV sensor diversity differences. The assessment of these differences shows that while the HFA relays and the four scram contactors for BWR/2 would result in a higher overall RPS failure frequency, the improved technical specification intervals and allowable out-of service times based on the generic plant would result in a net improvement to plant safety for plants with such differences. 'Ihe effect of other differences on the RPS failure frequency is insignificant. Therefore, the generic results can be applied to plants in the BWROG Technical Specification Improvement Program" Furthermore, GE has completed a Plant-Specific Report, which concludes that, the generic analysis in NEDC-30851P-A is applicable to VY. VY has reviewed the LTR and pir.at-specific report and verified applicability to VY.

Licensing Topical Report NEDC-30851P-A Suppl 2, Appendix A identifies VY as a participating utility in the development of the BWR Isolation Instrumentation Common to RPS (Reactor Protection System) and ECCS (Emergency Core Cooling System) Technical Specification Improvement Analysis. Section 3.3 specifically analyzes BWR 4 plants. VY has reviewed this LTR I and verified applicability to VY.

I l

I

C 1 --

""" ' Y^ *

• N ^" l'own coimm3um BVY 99-76 / Attachment I / Page 7 i-Licensing Topiw Report NEDC-31677P-A, updated Appendix E identifies VY as a participating utility in the development of the BWR Isolation Actuation Instrumentation not common to the RPS or ECCS Technical Specification Improvement Analysis. Section 5.1 and Appendix Cl specifically analyzes BWR 3/4 plants. VY has reviewed this LTR and verified applicability to VY.

Licensing Topical Report NEDC-30936P-A, Appendix N (Part 1) and Appendix B (Part 2) identifies VY as a participating utility in the development of the BWR ECCS Actuation Instrumentation Technical Specification Improvement Analysis. Section 5.4 (Part 2) specifically analyzes BWR 3/4 plants and GE has performed a plant specific review and confirmed VY applicability. VY has

reviewed the LTRs and plant-specific report and verified applicability to VY.

Licensing Topical Repon NEDC '0851P-A Suppl 1. Appendix B identifies VY as a participating

- utility in the development of the BWR Control Rod Block Instrumentation Technical Specification l- Improvement Analysis. Section 4.0 specifically addresses BWR 4 plants. VY has reviewed the LTR l and verified applicability to VY.

Licensing Topical Report GENE-770-06-1-A, identifies application of changes to surveillance test intervals and allowed out-of service times for Selected Instrumer.tation Technical Specifications to all BWR plants. VY has reviewed the LTR and verified applicability to VY.

l Licensing Topical Report GENE-770-06-2-A, identifies application of changes to surveillance test l intervals and allowed out-of-service times for Selected Instrumentation (BWR RCIC INSTRUMENTATION) Technical Specifications to all BWR plants. VY has reviewed the LTR and verified applicability to VY.

+ Demonstrate that the drin characteristics for RPS (SCRAM), ECCS, Isolation, Rod Block, and Selected Channel Instrumentation are bounded by the assumptions used in LTRs when the functional test interval is extended from monthly to quarterly. (This issue applies to all LTRs)

RESPONSE l l

This requirement as stated was difficult to address because the LTRs do not contain quantitative instrument driR assumptions. In order to resolve this concern, the BWR Owners' Group and the NRC staff reviewed the BWR setpoint calculation methodology and decided that additional clarification was in order. Consequently, the NRC staff provided additional guidance in a letter from C. E. Rossi (NRC) to R. F. Janecek (BWROG) dated April 27,1988, which specifically indicates that:

" ... licensees need only confirm that the setpoint drin which could be expected under the extended STis has been studied and either (1) has been shown to remain within the existing allowance in the RPS and ESFAS instrument setpoint calculation or (2) that the. allowance and setpoint have been adjusted to account for the additional expected driR."

l Vermont Yankee Plant Specific methods will support these criteria prior to implementation.

Instrument setpoint driR is monitored during channel calibration tests when setpoints are required to be verified. A concern exists for plants that have calibration intervals shorter than the proposed  !

l-quanerly functional tests. The TS have been reviewed and found not to contain a condition where calibration intervals would be less than the extended functional test surveillance interval.

L .-

l YEimONT YAMEE Nt'CIEAH POWER. CmWOHA HON )

BVY 99-76 / Attachment I / Page 8

]

l

+ Confirm that the differences between the parts of the RPS that perform the trip functions in the plant ,

and those of the base case plant were included in the specific analysis done using the procedures of '

Appendix K to NEDC-30851P-A. (This issue applies to LTR NEDC-30851P-A only)

RESPONSE l GE has completed a plant specific report that reviews applicability to the generic study completed in Licensing Topical Report NEDC30851P-A to increase STIs and add AOTs to the SCRAM (RPS)  ;

Instrumentation requirements in the Technical Specifications. This report utilizes the procedures of Licensing Topical Report NEDC-30851P-A, Appendix K to identify and evaluate the diffeiences between the parts of the SCRAM (RPS) that perform the trip functions at VY and those analyzed in l the generic study. The results of the analysis indicate that the differences and their impact do not significantly affect the improvement in the technical specifications developed by the generic efforts of Licensing Topical Report NEDC-30851P-A. Therefore, the conclusions reached in NEDC. 30851P-A apply to VY and the plant-specific changes contained in this request are bounded by both the generic analysis and the NRC SER.

APRM DOWNSCALE SCRAM ELIMINATION Although the IRM High Flux and Inoperative Trip Functions in RUN are listed as a RPS scram (RPS ,

LCO Table 3.1.1), they do not directly initiate a reactor scram. The trip performs an interlock function )

associated with the APRM downscale trip initiation. The interlock prevents the IRM High Flux / Inoperative scram function from being defeated in the RUN Mode until the APRM downscale  ;

setpoint has cleared (> 3/125 full scale).

The bases for removing the RUN Mode IRM High Flux / Inoperative with the associated APRM downscale scram Trip Function (APRM Downscale RUN Mode SCRAM) from TS is presented in a GE evaluation performed for VY. VY has reviewed this evaluation and has concurred with the conclusions. l This function existed on several early plants but was deleted from later plant designs. UFSAR and  ;

reload safety analyses do not take any credit for the APRM Downscale RUN Mode SCRAM. It is no l longer required by the STS and has been deleted from Technical Specifications of several plants that originally included it in their design.

Removal of the APRM Downscale RUN Mode SCRAM from TS will permit available combinations of inoperable IRM and APRM channels to be simultaneously bypassed, as intended by the plan'. design  !

(UFSAR 7.5.5.4 and 7.5.7.4). Due to independence of the bypass switches, some bypass combinations of l inoperable IRM and APRM channels could result in less than the minimum number of required operable IRM RUN trip functions, precluding bypm capability for one of the inoperable channels. Under these circumstances, the plant must remain in a " half scram" condition. Removal of this trip function from TS will avoid the need to operate the plant in the " half scram" condition, with the associated risk of a plant transient due to inoperable IRM/APRM combinations.

Removal of the IRM RUN Mode SCRAM function and associated notes from the Technical Specifications is not a safety concern for the following reasons:

a) The design basis accident in this region of operation (RUN Mode) is the control rod drop accident (CRDA). The only scram function that the UFSAR takes credit for in the mitigation of the CRDA is the APRM 120% power scram.

venmm nsm snmu Pom n connmunes BVY 99 76 / Att:chment I / P:ge 9 b) A Continuous Control Rod Withdrawal error (CWE) in RUN is terminated by the Rod Block Monitor (UFSAR 14.5.3). The APRM Reduced High Flux scram in conjunction with the IRM scram limits the consequences of the CWE during the STARTUP Mode, c) If the mode switch is changed to the RUN Mode prematurely during a hot or cold startup, the control rod block associated with the APRM downscale trip will activate, precluding funher control rod withdrawal. The control rod block feature is required by TS Table 3.2.5, and is not altered by the requested change.

d) If reactor power is reduced too far before changing the mode switch to the STARTUP Mode, the control rod block associated with the APRM downscale trip will activate, precluding control rod withdrawal. ' Also, procedures require IRMs to be fully inserted prior to changing modes from RUN to STARTUP and if the IRMs are not fully insened, a control rod withdrawal block would be activated after the mode switch was placed in STARTUP.

e) In addition, during a cold plant startup, prematurely changing to the RUN mode will result in MSIV closure due to insufficient steam pressure and subsequent scram if the reactor vessel pressure is < 800 psig.

Adding a new surveillance requirement to RPS Table 4.1.2 and corresponding description to the associated TS Bases to verify SRM/lRM/APRM overlap is being proposed to ensure that no gaps in  !

neutron flux indication exist from suberitical to power operations. The overlap between SRMs and IRMs )

is required to be demonstrated during reactor startup, to ensure that reactor power will not be increased l into a neutron flux monitoring region without adequate indication. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained.

The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. Overlap i between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings j such that the transition between the RUN and STARTUP/ HOT STANDBY Modes can be made without  !

either APRM downscale rod block, or IRM upscale rod block. This proposed change is consistent with l STS requirements.

Editorial corrections and administrative changes do not alter the meaning or intent of any requirements. l ECCS FUNCTION-SPECIFIC AOTs AND ACTIONS Below are explanations as to how the notes for TS Table 3.2.1 " Emergency Core Cooling System Actuation Instrumentation" and TS Table 3.2.9 ." Reactor Core isolation Cooling System Actuation l Instrumentation" that may be applied under different inoperable instrument channel scenarios. The  !

attached explanation is an attempt to provide reasonable explanations / scenarios for each note, but is not meant to be all-inclusive. The revised AOTs and actions are consistent with STS requirements for these Trip Functions. The repair AOTs are consistent with the intent of Licensing Topical Repon NEDC-30936P-A, Appendix N (Part 1) and Appendix B (Part 2) as implemented in the STS. Revising the test AOT to require initiation capability to be maintained is appropriate since this is provided for by design.

Therefore, there is no safety implication with this change.

There are 32 Trip Functions contained in Table 3.2.1 and 3 Trip Functions in Table 3.2.9. Below, Notes  ;

10 through 19 from Table 3.2.1 and Notes 6,7 and 9 from Table 3.2.9 are explained as to how they are  !

applied under different inoperable instrument channel scenarios. The application of Note 10 is explained  !

in detail. Notes 11 through 19 explanations are brief and discuss differences between the channels, l i

r i

WHuoNT hm Nrcuan Powtn Cmmonmos l BVY 99 76 / Attachment 1/ Page 10 L Table 3.2.1 Note 10, is for instrumentation inoperability conditions that affect Core Spray and/or LPCI trip functions. The required actions and completion times for the conditions described in Note 10 are contained in Notes 10.A,10.B, and 10.C. Shown below are several examples and explanations for the conditions, required actions, and associated completion times.

Example 1 (For Note 10 including required actions and completion times 10.A,10.B, and 10.C.)

l Hinh Drvwell Pressure (Table 3.2.1. item 1)

I l This trip function has four instruments total, two in each of two trip systems. The associated logic is l arranged as a one-out-of-two taken twice logic. i A. With one instrument channel inoperable, one of the two trip systems will g contain the required two operable instrument channels per trip system and Note 10 is applicable as stated in the last column of Table 3.2.1.

1. Note 10.A is met because system initiation capability is maintained.

2. Note 10.B requires the inoperable instrument channel to be placed in trip within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (unless the condition is sooner exited due to restoration of the instrument channel to an operable status.) If the instrument channel can not be placed in a trip condition (or tripping the channel is undesirable), action C (Note 10.C) is taken.

3. Note 10.C requires supported features of the Core Spray and/or LPCI to be declared inoperable if the required actions and completion times stated in Notes 10.A and 10.B were not met.

These required actions and completion times are identical to those stated in Standard Technical Specifications LCO 3.3.5.1, Required Actions B.3 and H.l.

1 l

B. With one instrument channel inoperable in each trip system, both of the two trip systems will not contain the required two operable instrument channels per trip system and Note 10 is applicable as stated in the last column of Table 3.2.1.

1. Note 10.A is met because. system initiation capability is maintained.

2. Note 10.B requires both of the inoperable instrument channels to be tripped within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (unless the condition is sooner exited due to restoration of both instrument channels to an operable status.) If both instrument channels cannot be placed in a tripped condition (or if tripping of both instrument channels is not desirable), action C (Note 10.C) is entered.

3. Note 10.C requires supported features of the Core Spray and/or LPCI to be declared  !

! inoperable if the required actions and completion times stated in Notes 10.A and 10.B were not met.

These required actions and completion times are identical to those stated in Standard Technical Specifications LCO 3.3.5.1, Required Actions B.1, B.3, and H.l.

1 I

l l

i j

"" "'""""*"C"""'"W"^

BVY 99 76 / Attachment I / Page 11 C. With two instrument channels inoperable in one trip system, one of the two trip systems will D.21 contain the required two operable instrument channels per trip system and Note 10 is applicable as stated in the last column of Table 3.2.1.

1. Note 10.A is pg.t met because system initiation capability is lost. (One of the two trip systems required for completion of the one-out-of-two taken twice logic cannot be tripped for the High Drywell Pressure trip function.) The affected supported features are required to be declared inoperable within one hour (unless action 10.A is met sooner due to restoration of one or both instrument channels to an operable status.)

2. Note 10.B requires both inoperable instrument channels to be tripped within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (unless the condition is exited sooner due to restoration of both instrument channels to an operable status.) If both instrument channels cannpt be placed in a tripped condition (or if tripping both instrument channels is not desirable), action C (Note 10.C) is entered.

3. Note 10.C requires features of the Core Spray and/or LPCI to be immediately declared inoperable if the required actions and completion times in Notes 10.A and 10.B were not met.

These required actions and completion times are identical to those stated in Standard Technical Specifications LCO 3.3.5.1, Required Actions B.1 and B.3.

Similar details apply to the remaining notes 11 through 19. The following is a brief explanation for the remainder of the notes and instrument channels.

Note 11 for Table Low Reactor Pressure is different from explanation of Table item above in that it is not desirable to place the channels in trip (to prevent pressurizing low pressure system piping), so they are required to be restored to an operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Ifinitiation capability of the supported features (i.e., opening of the Core Spray and LPCI injection) is inoperable, then the Core Spray or LPCI injection valves would be declared inoperable and the associated system LCO would be entered.

Note 12 applies to the low pressure ECCS actuation timers and similar to Note 10 for required actions.

Note 13 applies to LPCI Reactor Vessel Shroud Level and High Drywell Pressure. The difference between these items is the number of channels per trip system. Reactor Vessel Shroud has 2 trip systems, I channel per each trip system, and for High Daywell Pressure there are 4 channels,2 per each of the 2 trip systems. Note 13.B requires the inoperable channels to be placed in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This is similar to above HPCI High Reactor Vessel Level. However, placing the channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. If it is undesirable to place a channel in trip (i.e., in cases where placing the channel in trip will result in initiation), then the supported feature is declared inoperable per note 13.C.

Notes 14 and 17 are for instrumentation inoperability conditions that affect HPCI, and ADS functions -

contained in Table 3.2.1 and similar Notes 7 and 9 for Table 3.2.9 for RCIC. The notes are applied similarly to Note 10 above, except there are time differences for Note 17. Also all notes are different from Note 10 in that it is applied to systems rather than features. For HPC1/RCIC Low-Low Reactor Vessel Water Level there are 4 instrument channels,2 per trip system, as indicated in the first column of the table.

i l

yiwos, Yamm Nrcirau Ponn Colu'onA""N BVY 99 76 / Attachmint I / Page 12 Note 15 in Table 3.2.1 and Note 8 in Table 3.2.9 applies to Low Condensate Storage Tank Water Level.

These items are for features that realign the HPC1/RCIC pump suction from the condensate storage tank to the suppression chamber. There are two channels for one trip system for each of these items. If a

, channel becomes inoperable, Note 15.B. (8.B) applies and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed to either trip the channel or align the pump suction to the suppression chamber. If the initiation capability of the swap over

l. Ifeature is lost,- Note 15.A. (8.A) applies and I hour is allowed to either align the suction to the suppression chamber or declare the associated system (HPC1/RCIC) inoperable.

Note 16 in Table 3.2.1 and note 9 in Table 3.2.9 applies to HPCI/RCIC High Reactor Vessel Level. Both instrument trip functions are required to trip the HPC1/RCIC turbine and close the HPCI/RCIC steam supply valve respectively on reactor water high water level. There are a total of 2 Instruments in 1 trip system. Any one inoperable instrument channel will result in a loss of system initiation capability. Note 16.A (9.A) requires any inoperable channel be restored to operable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A risk-based analysis (NEDC-30936P-A, BWR Owners' Group Technical Specification Improvement Methodology With Demonstration for BWR ECCS Actuation Instrumentation, Past 2, December 1988) determined that an allowable out of service time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is acceptable to permit restoration of any' inoperable instrument channel to an operable status. If the channels cannot be restored to an operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the associated system is declared inoperable per note 16.B (9.B).

Note 18 applies to Core Spray /LPCI Pump Discharge Pressure and ADS Time Delay and is different from Note 10 described above in that inoperable channels are required to be restored to operable within i 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> verses placed in trip. The differences in the functions are the number of channels per trip system. Dependent on the number of inoperable channels and failure mode (whether in the tripped condition or not) would determine ifinitiation capability of ADS would be affected and whether or not Note 18.A. applies. Ifinitiation capability is maintained, then Notes 18.B,18.C, and 18.D apply.

Note 19 applies to Recirculation Pump Trip and is similar to the actions of Note 10 pith the exception of time restoration which is consistent with Standard Technical Specifications LCO 3.3.4.2, required actions A, B, C, and D.

1 RELOCATION OF ECCS HPCI, ADS, AND ISOLATION BUS POWER MONITORS l I

These trip functions are being deleted to be consistent with STS, and because they do not satisfy the 10 CFR 50.36 criteria for inclusion in the TS. These trip functions only provide control roam annunciation upon detection of abnormal conditions for the associated ECCS and Isolation. There functions are not ,

relied upon for detection or mitigation of any transient or accident, are not relied upon to detect  :

i degradation of the reactor coolant pressure boundary, and are not significant to public health and safety.

In addition, the existing TS requirements for these trip functions specify that an inoperable channel be tripped and this action would serve no purpose other than to cause annunciation in the control room. l i

Upon approval of this amendment application, the operability and surveillance requirements for these

. functions will be relocated and controlled in the Technical Requirements Manual described in the FSAR. i Any future change to the design, surveillance or operability requirements of these trip functions will be controlled under 10CFR50.59.

CONCLUSION As discussed above, VY has satisfactorily addressed the three issues for NEDC-30851P-A and the two I issues for the other GE LTRs. The Staff has indicated resolution of these issues are necessary to

i

""" " NCC"M"P"wruComouyuis BVY 99-76 / Attachm:nt I / P;ge 13 implement the generic technical specification changes identified in the LTRs on a plant-specific basis.

The first issue, which applies to all LTRs, required confirmation of the applicability of the generic analyses to VY. Two required plant-specific reports on SCRAM (RPS) and ECCS Instrumentation concluded that the generic analyses are applicable to VY. The reports addressed the differences between VY and the generic analyses and, when applied with the conclusions contained in NEDC-30851P-A and NEDC-30936P-A, justifies the proposed changes. VY has reviewed the LTRs and plant specific reports and verified applicability to VY. The second issue required demonstrating that instrument setpoints can remain unchanged because drift assumptions remain the same. A concern exists for plants that have TS calibration intervals shorter than the proposed quarterly functional tests. For those cases, an extension of the functional test interval would then require consideration of the effects on setpoint drift. The celibration intervals for the VY TS instrumentation addressed by these LTRs have been verified to be equal to or longer than once per quarter and are therefore unaffected by the proposed changes. The third issue, which applies only to NEDC-30851P-A for RPS (SCRAM), required confirmation that the base plant and VY RPS (SCRAM) trip function differences allowed VY to be bounded by the LTR. GE plant-specific report confirmed that the VY differences and their impact do not significantly affect the improvement in the Technical Specifications developed by the generic efforts of NEDC-30851P-A.

In addition as discussed above, VY concludes that the proposed changes to remove the RUN Mode IRM l High Flux / Inoperative with the associated APRM downscale scram Trip Function is safe and justified.

These changes will enhance general understanding of neutron monitoring TS surveillance requirements for VY.

Use of ECCS Function-specific AOTs, actions and relocation of Bus Power Monitors is consistent with STS and will provide better understanding of the instrumentation tables.

Consistent with these factors, the NRC has approved similar amendments incorporating the above  ;

changes. Amendment No. 250 dated January 12,1999 for the James A. FitzPatrick Nuclear Power Plant added function specific AOTs and Amendment No.103 dated October 27,1997 for the Millstone Unit No.1 deleted the APRM downscale RUN Mode SCRAM. In addition, Amendment No. 227 dated September 11,1995 for the James A. FitzPatrick Nuclear Power Plant removes the APRM downscale RUN Mode SCRAM and implemented STI and AOT for selected instrumentation.

i VI'.ituoNT YAni.it Nrci.i: Ant Pows:.it Costi>oitxtios Docket No. 50-271 BVY 99-76 I

l l

i Attachment 2 l

Vermont Yankee Nuclear Power Station l

Proposed Technical Specification Change No. 217 Surveillance Test Interval (STI) and Allowable out-of-service Time (AOT)

Determination of No Significant Hazards Consideration

"M"M Y^miNuun Powi;u coimonmos BVY 99-76 / Attachment 2 / Page !

Pursuant to 10CFR50.92, VY has reviewed the proposed change and concludes that the change does not involve a significant hazards consideration since the proposed change satisfies the criteria in j- 10CFR50.92(c).

1. The operation of Vermont Yankee Nuclear Power Station in accordance with the oronosed amendment. will not involve a sienificant increase in the orobability or conseauences of an accident oreviousiv evaluated.

VY has determined that the proposed change does not involve a significant increase in tne probability or

. consequences of an accident previously evaluated. The generic analysis contained in Licensing Topical Report NEDC-30851P-A assessed the impact of changing SCRAM (RPS) surveillance test intervals for Logic and Functional tests (STIs) and adding allowable out-of-service times (AOTs) on the SCRAM (RPS) failure frequency, the scram frequency and equipment cycling. Specifically, Section 5.7.4, l "Significant Hazards Assessment," of NEDC-30851P-A states that

!

l

" Fewer challenges to the safeguards system, due to less frequent testing of the RPS, conservatively results in a decrease of approximately one percent in core damage frequency. This decrease is based upon the following:

Based on the plant-specific experience presented in Appendix J, the estimated reduction in scram frequency (0.3 scrams / yr.) represents a 1 to 2 percent decrease in core damage frequency based .

on the BWR plant-specific Probabilistic Risk Assessments (PRAS) listed in Table 5-8.

l The increase in core damage frequency due to less frequent testing is less than one percent. This ,

- increase is even lower (less than 0.01 percent) when the changes resulting from the j implementation of the Anticipated Transients Without Scram (ATWS) rule are considered.

Therefore, this increase is more than offset by the decrease in CDF due to fewer scrams.

The effect of reducing unnecessary cycles on RPS equipment, although not easily quantifiable, also results in a decrease in core damage frequency.

The overall impact on core damage frequency of the changes in allowable out-of-service times is negligible."

From this generic analysis, the BWR Owners' Group concluded that the proposed changes do not significantly increase the probability or consequences of an accident previously evaluated, namely the increase in probability of a scram failure due to SCRAM (RPS) unavailability is insignificant, and the overall probability of an accident is actually decreased as the time the SCRAM (RPS) Instrumentation logic operates as designed is increased resulting in less inadvertent scrams during testing and repair.

Furthermore, the plant specific reports demonstrates that although VY differs from the generic model analyzed in License Topical Report NEDC-30851P-A, the net effect of the plant-specific differences do not alter the generic conclusions.

The generic analysis contained in Licensing Topical Reports NEDC-30851P-A Suppl 2/NEDC-31677P-A assessed the impact of changing STIs and AOTs for BWR Isolation Instrumentation common /not common to SCRAM (RPS) and ECCS instrumentation. Specifically, Section 4.0, " Summary of Results,"

ofNEDC-30851P-A Suppl 2 states that:

"The results indicate that the effects on probability of failure to initiate isolation are very small and the effects on probability or frequency of failure to isolate are negligible in nearly every case. In addition, l

Vr.nuum YAmm Necu.Au l'owtu ConPonmoN

\ BVY 99-76 / Attachment 2 /Page 2 l the results indicate that increasing the AOT to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for tests and repairs has a negligible effect on the l probability of failure of the isolation function. These combined with changes to the testing intervals and

. allowed out-of-service times for RPS and ECCS instrumentation provide a net improvement to plant safety and operations."

l and Section 5.6, " Assessment of Net Effect of Changes," of NEDC-31677P-A states that:

"A reduction in core damage frequency (CDF) of at least as much as estimated in the ECCS instrumentation analysis can be expected when the isolation actuation instrumentation STIs are changed from one month to three months. The chief contributor to this reduction is the channel functional tests for the MSIVS. Inadvertent closure of the MSIVs will cause an unnecessary plant scram. This reduction in CDF more than compensates for any small incremental increase (10% or 1.OE-07/ year) in calculated isolation function failure frequency when the STI is extended to three months."

From this generic analysis, the BWR Owners' Group concluded that the proposed changes do not significantly increase the consequences of an accident previously evaluated, namely the increase in probability of an isolation failure due to isolation instrumentation unavailability is insignificant, and the overall probability of an accident is actually decreased as the time the SCRAM (RPS) Instrumentation j logic operates as designed is increased resulting in less inadvertent scrams during testing and repair.

l lThe generic analysis contained in Licensing Topical Report NEDC-30936P-A (Parts 1 and 2) assessed the impact of changing STIs and AOTs for all BWR ECCS Actuation Instrumentation. Specifically, Section 4.0, " Technical Assessment of Changes," of NEDC-30936P-A (Past 2) states that:

l' "The results indicate an insignificant (less than SE-7 per year) increase in water injection function failure L frequency when STIs are increased from 31 days to 92 days, AOTs for repair of the ECCS actuation instrumentation are increased from one hout to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and AOTs for surveillance testing are increased from two to six hours. For all four BWR models the increase represents less than 4% increase in failure frequency. However, when other factors which influence the overall plant safety are considered, the net result isjudged to be an improvement in plant safety."

From this generic analysis, the BWR Owners' Group concluded that the proposed changes do not significantly increase the probability or consequences of an accident previously evaluated, namely the

. increase in probability of a water injection failure due to ECCS instrumentation unavailability is insignificant and the net result is judged to be an improvement in plant safety. Furthermore, the plant-specific report demonstrates that although VY differs from the generic model analyzed in Licensing Topical Report NEDC30936P-A, the net affect of the plant-specific differences do not alter the generic l conclusions.

The generic analysis contained in Licensing Topical Report NEDC-30851 P-A Suppl 1, assessed the impact of char.ging Rod Block STis on Rod Block failure frequency. Specifically, Section 5 (BNL's I

_ Tech. Eval. Report - Attach. 2 to the NRC SER) of NEDC-30851 P-A Suppl I states that:

'"The BWR Owners' Group proposed changes to the Technical Specifications concerning the test requirements for BWR control rod block instrumentation. The changes consist of increasing the surveillance test intervals from one to three months. These test interval extensions are consistent with the already approved changes to STIs for the reactor protection system. The technical analysis reviewed and verified as documented herein indicates that there will be no significant changes in the availability of the control rod block function if these changes are implemented. In addition, there will be a negligible impact on the plant core melt frequency due to the decreased testing."

L I

l-

"""" hu Nrcuun Ponn Coni.ony um BVY 99-76 /AttachmInt 2 / Page 3 From this generic analysis, the BWR Owners' Group concluded that the proposed changes do not significantly increase the probability of an accident previously evaluated or consequences of an accident previously evaluated.

Bases contained in GE Topical Report GENE-770-06-1 assessed the impact of changing STIs and AOTs on selected systems failure frequency. Specifically, Section 2.0, " Summary," of GENE 770-06-1 states that:

i

" Technical bases are provided for selected proposed changes to the instrumentation STIs and AOTs that were identified in the BWROG Improved BWR Technical Specification activity. These STI and AOT ,

changes are consistent with approved changes to the RPS, ECCS, and isolation actuation I instrumentation. These proposed changes do not result in a degradation to overall plant safety."

From these Bases, the BWR Owners' Group concluded that the proposed changes do not significantly increase the probability of an accident previously evaluated or consequences of an accident previously l evaluated. l Bases contained in GE Topical Report GENE-770-06-2 assessed the impact of changing STIs and AOTs on selected systems (RCIC Actuation) failure frequency. Specifically, Section 2.0, " Summary," of J

GENE 770-06-2 states that: -

"The STI and AOT changes to the RCIC actuation instrumentation are justified based on their small effect on the water injection function unavailability and consistency with comparable changes to the j actuation instrumentation for the other ECCS subsystems". These STI and AOT changes are consistent i with approved changes to the RPS, ECCS, and isolation actuation instrumentation. These proposed j changes do not result in a degradation to overall plant safety."

)

From these Bases, the BWR Owners' Group concluded that the proposed changes do not significantly  !

increase the probability of an accident previously evaluated or consequences of an accident previously evaluated.

The proposed change will not alter the physical characteristics of any plant systems or components and all safety-related systems and components remain within their applicable design limits. Thus, system and component performance is not adversely affected by this change, thereby assuring that the design capabilities of those systems and components are not challenged in a manner not previously assessed so as to create the possibility of a new or different kind of accident. ,

~

The addition of allowable out-of service times (AOTs) and the increase in surveillance test intervals (STIS) does not alter the function of the SCRAM (RPS), ECCS, Isolation, Rod Block, and Selected Instrument Systems nor involve any type of plant modification and no new modes of plant operation are involved with these changes.

No physical change is being made to any systems or components that are credited in the safety analysis, therefore there is no change in the probability or consequences of any accident analyzed in the UFSAR.

The design basis accident applicable to the startup power region is the Control Rod Drop Accident (CRDA). The UFSAR does not credit the RUN Mode IRM High Flux / Inoperative with the associated APRM downscale scram Trip Function (APRM downscale RUN Mode SCRAM) in the termination of this accident. Accident mitigation is provided by the APRM 120% power scram. Therefore, elimination

i VamoNT YAun NormAu l'owru ComumanoN

!- BVY 99-76 / Attachment 2 / Page 4 l

l I

of the APRM downscale RUN Mode SCRAM function has no adverse affect on previously evaluated accidents.

The Continuous Control Rod Withdrawal Error (CWE) transient is terminated by the Rod Block Monitor  ;

(RBM) in the RUN Mode. The APRM Reduced High Flux Scram provides the primary STARTUP l Mode protection in conjunction with the IRMs and limits the consequences of this transient. Therefore, elimination of the APRM downscale RUN Mode SCRAM function has no effect on the consequences of this transient.

Adding a new surveillance to verify SRM/IRM/APRM overlap will enhance neutron monitoring during startups and shutdowns and does not have an adverse affect on previously evaluated accidents.

None of the proposed changes will affect any of the rod blocks or other precursor events to either the CRDA or CWE. Therefore, there is no change in the probability of any accident previously analyzed. ,

Use of ECCS Function-specific AOTs, actions and relocation of Bus Power Monitors to a licensee controlled document is consistent with STS and does not have an adverse affect on previously evaluated accidents, In addition, VY concluded the editorial corrections and administrative changes do not involve a i significant increase in the probability or consequences of an accident previously evaluated. These l changes do not alter the meaning or intent of any requirements.  !

I

2. The operation of Vermont Yankee Nuclear Power Station in accordance with the orooosed l amendment. will not create the nossibility of a new or different kind of accident from any  !

accident oreviously evaluated.

VY has determined that the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

The proposed change will not alter the physical characteristics of any plant systems or components and all safety-related systems and components remain within their applicable design limits. Thus, system i and component performance is not adversely affected by this change, thereby assuring that the design capabilities of those systems and components are not challenged in a manner not previously assessed so as to create the possibility of a new or different kind of accident. Editorial corrections and administrative ;

changes do not alter the meaning or intent of any requirements.

The addition of allowable out-of-service times (AOTs), ECCS function-specific actions and the increase l in surveillance test intervals (STis) does not alter the function of the SCRAM (RPS), ECCS, Isolation, Rod Block, and Selected Instrument Systems nor involve any type of plant modification and no new i modes of plant operation are involved with these changes. Therefore, operation in accordance with the l proposed amendment will not create the possibility of a new or different kind of accident from any accident previously evaluated.

Elimination of APRM downscale RUN Mode SCRAM function affects only the operations of neutron monitoring and protective systems (IRM and APRM) which provide indication and mitigation actions only. Operation of these systems does not create the possibility for new precursors (such as reactivity) which would introduce a new or different kind of accident from any accident previously evaluated.

y

"""" Y^* **^" l'oun Concours ms BVY 99-76 /Attachmint 2 / Page 5 l Additionally, the proposed changes do not affect the ability of those systems required to mitigate previously evaluated accidents during the modes they are credited.

l 3. The oneration of Vermont Yankee Nuclear Power Station in accordance with the proposed l Amedment. will not involve a sinnificant reduction in a marnin of safety.

l The NRC staff has reviewed and approved the generic studies contained in the GE Topical Reports j -(LTRs) and has concurred with the BWR Owners' Group that the proposed changes do not significantly affect the availability of the SCRAM (RPS), ECCS, Isolation, Rod Block, or Selected Instrument

- Systems. The proposed addition of allowable out-of-service times (AOTs) for the instruments addressed l in the LTRs provide reasonable time for making repairs and performing tests. The lack of sufficient AOTs in the current Technical Specifications (TS) creates a hurried atmosphere during repairs and tests that could cause an increased risk of error, in addition, placing an individual channel in a tripped 1 l condition because no AOT exists, as in the current TS, increases the potential of an inadvertent scram.

l The proposed AOTs provide realistic times to comple*e the required actions without increasing the l overall instrument failure frequency. Use of ECCS Function-specific AOTs, actions and relocation of Bus Power Monitors to a licensee controlled document is consistent with STS and there is no significant l reduction in the margin of safety.

' Editorial corrections and administrative changes do not alter the meaning or intent of any requirements.

! 'Iherefore, there is no significant reduction in the margin of safety.

The incorporation of extended surveillance test intervals (STis) does not result in significant changes in the probability of instrument failure, as demonstrated by the LTRs. In addition, the TS calibration )

frequency has not changed, and therefore assurance exists that the setpoints will not be affected by drift :

These changes, when coupled with the reduced probability of test-induced plant transients and equipment failures, result in an overall increase in the margin of safety,

! The only scram function that the UFSAR takes credit for in the mitigation of the limiting accident l- (control rod drop accident) is the APRM 120% power scram which is not affected by this change. Only the APRM Downscale RUN Mode SCRAM, for which the UFSAR takes no credit in the termination of any analyzed event, is removed by this change. Removal of the APRM Downscale RUN Mode SCRAM will avoid the need to operate the plant in a " half scram" condition with the potential for an inadvertent

! plant transient. For these reasons, the change does not involve a significant reduction in a margin of

safety.

The Continuous Control Rod Withdrawal Error (CWE) transient is terminated by the Rod Block Monitor (RBM) in the RUN Mode. When initiated from the STARTUP Mode, the consequences of a CWE are L limited by the APRM Reduced High Flux scram in conjunction with the IRM scram function. Therefore

eliminating the TS requirement for the APRM Downscale RUN Mode SCRAM will not reduce the j margm of safety for this transient.

t Adding a new surveillance to verify SRM/lRM/APRM overlap will enhance neutron monitoring during startups and shutdowns and consequently does not involve a significant reduction in a margin of safety.

On the basis of the above, VY has determined that operation of the facility in accordance with the proposed change does not involve a significant hazards consideration as defined in 10CFR50.92(c), in that it: (1) does not involve a significant increase in the probability or consequences of an accident previously evaluated; (2) does not create the possibility of a new or different kind of accident from any accident previously evaluated; and (3) does not involve a significant reduction in a margin of safety.

L