ML18053A698

NUREG-0887, Supp 2, Safety Evaluation Report Related to the Operation of Perry Nuclear Power Plant, Units 1 and 2

ML18053A698
Person / Time
Site:	Perry
Issue date:	01/31/1983
From:	Office of Nuclear Reactor Regulation
To:
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NUDOCS 8302100276, NUREG-0887 S02
Download: ML18053A698 (60)

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NUREG..(817 Supplement No. 2 E1,*.. Report related to the operation of

• Perry Nuclear Power Plant, Units 1 and 2 Docket Nos. 50-440 and 50-441 Cleveland Electric Illuminating Company U.S. Nuclear Regulatory Commiseion Office of Nuclear Reactor Regulation January 1983 830;) 1002 7b 8 HJ l J J.

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NUREG-(1187 Supplement No. 2 lufety Evaluadon Repo1t related to the operation of Perry Nuclear Power Plant, Units 1 and 2 Docket Nos. 5()..440 and 60-441 Cleveland Electric Illuminating Col'T'Mny U.S. Nuclear Regulatory Commission Office of Nuclear RNctor Regulation January 1983

ABSTRACT Supplement No. 2 to the Safety Evaluation Report on the application filed by the Cleveland Electric Illuminating Company on behalf of itself and as agent for the Duquesne Light Company, the Ohio Edison Company, the Pennsylvania Power Company, and the Toledo Edison Company (the Central Area Power Coordination Group (CAPCO)), as applicants and owners, for a license to operate the Perry Nuclear Power Plant, Units 1 and 2 {Docket Nos. 50-440 and 50-441), has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission. The facility is located in Lake County, Ohio. This supplement reports the status of certain issues that had not been resolved at the time of publication of the Safety Evaluation Report and Supplement No. 1 to that report.

Perry SSER 2 iii

TABLE OF CONTENTS ABSTRACT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii ABBREVIATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iX 1 INTRODUCTION AND GENERAL DESCRIPTION................................ 1-1 1.1 Introduction................................................... 1-1 1.9 Outstanding Issues............................................. 1-2 1.10 Confirmatory Issues............................................ 1-3 1.11 License Conditions............................................. 1-6 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS............. 3-1 3.9 Mechanical Systems and Components.............................. 3-1 3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment........................................... 3-1 3.9.2.3 Preoperational Flow-Induced Vibration Testing of Reactor Internals........................... 3-1 3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Support Structures........................ 3-1 3.9.3.3 Component Supports............................. 3-1 4 REACTOR. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 4.2 Fuel System Design............................................. 4-1 4.2.3 Design Evaluation....................................... 4-1 4.2.3.1 Fuel System Damage Evaluation.................. 4-1 (5) Dimensional Changes........................ 4-1 5 REACTOR COOLANT SYSTEM.............................................. 5-1 5.3 Reactor Vessel Materials, Fabrication, and Integrity........... 5-1 5.3.1 Reactor Vessel Materials................................ 5-1 (1) Compliance with Appenaix G, 10 CFR 50.... .. ...... .. 5-1

{2) Compliance with Appendix H, 10 CFR 50.... ... .... .. . 5-2 Perry SSER 2 V

TABLE OF CONTENTS (Continued).

Page 6 ENGINEERED SAFETY FEATURES .............................. ,........... 6-1

6. 2 Containment Sys terns. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1

6. 2.1 Containment Functional Design........................... 6-1 6.2.1.9 Secondary Containment.......................... 6-1 6.2.3 Containment Isolation System............................ 6-1 6.2.6 Containment Ledkage Testing............................. 6-2 6.2. 7 TMI-2 Requirements...................................... 6-4 (3) Containment Isolation Dependability {TMI Action Plan Item II. E. 4. 2)................................. 6-4 6.3 Emergency Core Cooling System {ECCS). .... ... ............ ....... 6-4

6. 3.1 System Description...................................... 6-4 6.3.1.3 Functional Design.............................. 6-4 6.4 Control Room Habitability Systems............................... 6-6 7 INSTRUMENTATION AND CONTROLS........................................ 7-1 7.2 Reactor Protection Systems..................................... 7-1 7.2.2 Specific Findings....................................... 7-1 7.2.2.4 Scram Discharge Volume Level Monitoring System......................................... 7-1 7.3 Engineered Safety Features {ESF) Systems....................... 7-1 7.3.2 Specific Findings....................................... 7-1 7.3.2.2 High-Pressure Core Spray Syste~... ...... ....... 7-1 7.3.2.6 Periodic Testing of ESF Actua on Systems During Plant Operation......................... 7-1 7.3.2.7 Manual Initiation and Termination of ESF Systems........................................ 7-2 7.4 Systems Required for Safe Shutdown............................. 7-3 7.4.2 Specific Findings....................................... 7-3

7. 4. 2. 2 Remote Shutdown System......................... 7-3 7.4.2.4 RCIC Testing Procedures........................ 7-3 Perry SSER 2 vi

TABLE OF CONTENTS (Continued)

Page 7.5 Safety-Related Display Instrumentation......................... 7-4 7.5.2 Specific Findings....................................... 7-4 7.5.2.5 Additional Accident-Monitoring Instrumentation (TMI Action Plan Item II.F.1, Positions 4, 5, and 6)...................................... 7-4

7. 7 Cont ro 1 Sys ttms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 7.7.2 Specific Findings....................................... 7-4 7.7.2.3 Failures in Vessel Level Sensing Lines Common to Control and Protection Systems (LRG-II Generic Issue 1-ICSB).................. 7-4 8 ELECTRIC POWER SYSTEMS.............................................. 8-1 8.2 Offsite Power Systems.......................................... 8-1 8.2.4 Adequacy of Station Electric Distribution System Voltages................................................ 8-1 9 AUXILIARY SYSTEMS................................................... 9-1 9.1 Fuel Storage Facility.......................................... 9-1 9.1.5 Overhead Heavy-Load-Handling System..................... 9-1 9.3 Process Auxiliaries............................................ 9-1 9.3.4 Standby Liquid Control System........................... 9-1 9.5 Fire Protection Systems........................................ 9-1 9.5.1 Introduction............................................ 9-1 9.5.1.4 General Plant Guidelines ...................... . 9-1 9.5.1.4.2 Safe Shutdown Capability ........... . 9-]

9.5.1.6 Fire Protection of Specific Plant Areas ....... . 9-2 9.5.LG.2 Control Room ....................... . 9-2

9. 6 Other Auxiliary Systems ........................................ . 9-3 9.6.3 Emergency Diesel Engine Fuel Oil Storage and Transfer System .................................................. . 9-3 Perry SSER 2 vii

TABLE OF CONTENTS (Continued) 9.6.3.l Emergency Diesel Engine Auxiliary Support Structures (General)............................ 9-3 (4) Testing No-Load, Light Load Operation...... 9-3 12 RADIATION PROTECTION................................................. 12-1 12.3 Radiation Protection Design Features............................ 12-1

12. 3. 2 Shielding............................................... 12-1 12.3.4 Area Radiation and Airborne Radioactivity Monitoring Instrumentation......................................... 12-1 12.3.4.1 Area Radiation Monitoring Instrumentation..... 12-1 13 CONDUCT OF OPERATIONS................................................. 13-1

13. 2 Training Program................................................ 13-1 13.2.1 Licensed Operator Training Program ...................... 13-1 13.2.1.9 Operator Requalification Program .............. 13-1 13.2.2 Training for Nonlicensed Plant Staff .................... 13-1

13. 2. 2.1 Conclusion.................................... 13-1

13. 5 Plant Procedures................................................. 13-2 13.5.1 Administrative Procedures ................................ 13-2 13.5.1.8 Shift Supervisor Responsibilities .............. 13-2 13.5.1.11 Verify Correct Performance of Operating Activities..................................... 13-2 16 TECHNICAL SPECIFICATIONS.............................................. 16-1 18 CONTROL ROOM DESIGN REVIEW ............................................ 18-1 APPENDICES A CONTINUATION OF CHRONOLOGY - PERRY NUCLEAR POWER PLANT (UNITS 1 AND 2)

B REFERENCES C UNRESOLVED SAFETY ISSUES Task A-11, Reactor Vessel Mat~~ials Toughness E NRC STAFF CONTRIBUTORS AND CONSULTANTS G ERRATA TO THE SAFETY EVALUATION REPORT Perry SSER 2 viii

ABBREVIATIONS ACRS Advisory Committee on Reactor Safeguards ADS automatic depressurization system AISC American Institute of Steel Construction ALARA as low as is reasonably achievable ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials ATWS anticipated transient(s) without scram BOP balance of plant BTP Branch Technical Position BWR boiling-water reactor CAPCO Central Area Power Coordination Group CEI Cleveland Electric Illuminating Company CFR Code of Federal Regulations CP construction permit CRO control rod drive DCRDR detailed control room design review ECCS emergency core cooling system EHC electrohydraulic control ESF engineered safety feature(s)

FSAR Final Safety Analysis Report GDC General Design Criterion(a)

GE General Electric HCU hydraulic control unit HED human engineering discrepancy HPCS high-pressure core spray IE Office of Inspection and Enforcement IFTS inclined fuel transfer system INPO Institute of Nuclear Power Operations La maximum allowable leakage rate at pressure Pa LOCA loss-of-coolant accident LPCI low-pressure coolant injection LPCS low-pressure core spray LRG-11 Licensing Review Group-II MCPR minimum critical power ratio MSIV main steam isolation valve MWd/MTU megawatt days per metric ton of uranium NIOSH N_tional Institute of Occupational Safety and Health NPTS Nuclear Project Training Section NSSS nuclear steam supply system OL operating license OSHA Occupational Safety and Health Act Pa calculated peak containment pressure PGCC power generation control complex PPOTU Perry Plant Department Training Unit psig pounds per square inch gage QA quality assurance Perry SSER 2 ix

RCIC reactor core isolation cooling RCPB reactor coolant pressure boundary RV relief valve SOV scram discharge volume SER Safety Evaluation Report SSER Supplemental Safety Evaluation Report SRV safety relief valve SV safety valve TMI Three Mile Island Perry SSER 2 X

1 INTRODUCTION AND GENERAL DISCUSSION 1.1 Introduction The Nuclear Regulatory Commission's Safety Evaluation Report (NUREG-0887) on the application of the Cleveland Electric Illuminating Company (CEI or the ap-plicant) for a license to operate the Perry Nuclear Power Plant, Units 1 and 2, was issued in May 1982. Supplement No. 1 to the Safety Evaluation Report (SER) was issued in August 1982. The purpose of this supplement is to further update the SER by providing the results of the staff's review of information submitted by the applicant by l~tter or in meetings to address some of the issues in Sec-tions 1.9, 1.10, and 1.11 of the SER that remain unresolved. The information provided in the applicant's letters must be acceptably documented in Amendments to the Final Safety Analysis Report (FSAR) before licensing.

Each section or appendix of this Supplemental Safety Evaluation Report (SSER) is designated and titled so that it corresponds to the section or appendix of the SER that has been affected by the staff's additional evaluation, and except where specifically noted, does not replace the corresponding SER section or appendix. Appendix A is a continuation of the chronology of correspondence between NRC and the applicant that updates the list in the SER and SSER No. 1.

Appendix Bis a list of references cited in this report.* Appendix C addresses the staff's resolution of Unresolved Safety Issue, Task A-11. Appendix Eis a list of principal staff contributors to this supplement. Appendix G is a list of additional errata to the SER. No changes were made to SER Appendices Dor F in this supplement.

Copies of this supplement are available for public inspection at the Commission's Public Document Room at 1717 H Street, N.W., Washington, O.C. and at the Perry Public Library, 3735 Main Street, Perry, Ohio.

The NRC Project Manager is John J. Stefano. Mr. Stefano may be contacted by calling (301) 492-7037 or by writing to the following addr~ss:

John J. Stefano Division of Licensing U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Copies of this supplement are also available for purchase from the sources

'indicated on the inside front cover of this report.

• Availability of all material cited is described on the inside Front cover of this report.

Perry SSER 2 1-1

1.9 Outstanding Issues In Section 1.9 of the SER, the staff identified 19 outstanding issues that had not been resolved at the time the SER was issued in May 1982. Three of those issues were reported as satisfactorily resolved and Issue {20) was added in SSER No. 1. This supplement discusses those issues that have been resolved since SSER No. 1 was issued in August 1982, as well as the status of those issues that continue to remain unresolved. Outstanding Issue {3) has been changed to Confirmatory Issue (53). An additional outstanding issue is being added in this supplement as Issue (21), namely, "Reanalysis of transients and accidents: development of emergency operating procedures per TMI Action Plan Item I.C.l (13.5.2.1). 11 The status of each issue is indicated below. If the issue is discussed in this supplement, the section where it is discussed is identified. Resolution of the remaining outstanding issues will be addressed in a future supplement to the SER.

Issue Status Section (1) Tur~ine missile protection Under review; awaiting addi-tional informa-tion (2) Seismic system and subsystem Resolved in analysis SSER No. 1 (3) Reactor internal vibration prototype Changed to 3.9.2.3 (BWR/6-238 in.) test program Confirmatory Issue {53)

(4) Environmental/seismic and dynamic Under review qualification of Category I mechani-cal and electrical equipment (5) Inservice testing of pumps and Awaiting valves information (6) Transient and accident analysis for Resolved in ECCS, overpressure, and operating SSER No. 1 MCPR (7) Control room design Interim DCROR 18 audit performed (8) Mark III containment system issues Awaiting (Humphrey issues) information (9) Pool dynamic loads Awaiting information (10) Containment purge Under review (11) Periodic testing of ADS actuation Resolved 7.3.2.6 systems during plant operation (12) Manual initiation/termination of Review progress 7.3.2.7 ESF systems update - awaiting information Perry SSER 2 1-2

Issl.le Stc1tus Section (13) IE Bulletin 79-27 Awaiting information (14) Control system failures Awaiting information (15) Fire protection - safe shutdown Resolved 9. 5.1.4. 2

{16) Fire protection - PGCC system (CO 2 Resolved 9. 5.1. 6. 2 vs Halon fire suppressant in control room)

(17) HPCS engine skid piping Resolved in SSER No. 1 (18) Interim shifting staffing for two- Deferred; applies unit operation to Unit 2 only

{19) Emergency plans Awaiting information

{20) Standby liquid control system final Added in SSER 9.3.4 design No. 1 - update on revised system design status; awaiting information (21) Reanalysis of transients and Awaiting accidents: development of emer- information gency operating procedures per TMI Action Plan Item I.C.1 1.10 Confirmatory Issues In Section 1.10 of the SER, the :;taff identified 49 confirmatory issues that were not fully resolved when the SER was issJed. Five of those issues were resolved and Issue (50) was added in SSER No. 1 (Issue (50) was cited as License Condition (8) in the SER). This supplement discusses those issues that have been resolved since SSER No. 1 wus issued and adds three new issues - (51),

(52), and (53). The status of each confirmatory issue is addressed below. If the issue is discussed in this supplement, the section where it is discussed is noted. Resolution of the remaining confirmatory issues will be addressed in a future supplement to the SER.

Issue Status Section (1) Piping final stress analysis Awaiting information

{2) Containment buckling analysis Reso 1ved in SSER No. 1 (3) Containment ultimate capacity Resolved in analysis SSER No. 1 (4) Emergency service water tunnel Resolved in structure analysis SSER No. 1 Perry SSER 2 1-3

Issue Status Section (5} Vibration monitoring program for Resolved in BOP systems SSER No. 1 (6) Mark III hydrodynamic loads Deleted - same as Outstanding Issue (9) in Section 1. 9 (7) Testing relief/safety valves per TMI Under review Action Plan Item 11.0.1 (8) IE Bulletin 79-02 Under review (9) Dual function pipe whip/support Resolved 3.9.3.3 restraints (10) Hydrodynamic load effect on CRD/HCU Under review (11) Fuel mechanical fracturing Under review (12) Fuel assembly damage from external Under review sources (13) Fuel rod bow1ng Under review (14) Overheating of gladolinia fuel Under review pellets (15) Preservice inspection program Awaiting information (16) Material surveillance capsules - RV Resolved 5.3.1(2) beltline (17) Fracture toughness RCPB materials Resolved - site confirmatory audit required before fuel load (18) HPCS and RCIC initiation per TMI Site confirmatory Action Plan Item II.K.3.13 audit required to resolve (19) Isolation of HPCS and RCIC per TM! Site confirmatory Action Plan Item II.K.3.15 audit required to resolve (20) Subcompartment pressure analysis Under review

{21) Suppression pool temperature limits Awaiting information (22) Secondary containment penetration Resolved 6.2.1.9 leakage (23) Containment isolation dependability Reso 1ved 6.2. 7(3) per TMI Action Plan Item 11.E.4.2 (24) Type C test of all ECCS injection Reso 1ved 6.2.6 valves Perry SSER 2

Issue Status Section (25) ADS logic 11<>dification per THI Awaiting Action Plan Item II.K.3.18 information - also added as License Condition (17) in this supplement (26) ATWS recirculating pump trip Awaiting information (27) Modified SUV level monitoring system Resolved 7.2.2.4 (28) HPCS initiation circuitry final Resolved - site 7.3.2.2 design confirmatory audit required before fuel load (29) Remote shutdown panel nonsafety- Resolved 7.4.2.2 grade readouts (30) RCIC testing procedures Resolved 7.4.2.4 (31) Calibration tor k~/SV pressure Resolved - site SER 7.5.2.1 switches confirmatory audit required before fuel load (32) Accident monitoring per TMI Action Resolved 7.5.2.5 Plan Items II.F.1.4, II.F.1.5, and II.F.1.6 (33) Failures in vessel level sensing Resolved 7. 7.2.3 lines co111111on to control and reactor protection systems (34) Final valve design setpoint and Resolved 8.2.4 analysis (35) Physical separation of redundant Resolved - site electrical systems confirmatory audit required before fuel load (36) Documentation or test of 3-hour-fire Test required to resistance of gypsum board walls resolve - awaiting information (37) light and communication fire Under review protection features (38) Revision of fire protection stand- Under review pipe and hose locations (39) Portable fire extinguisher locations Under review (40) Watertight curbs in switchgear/ Under review diesel generator rooms (41) Design for noble gas effluent Awaiting MOnitors per TM! Action Plan information Item II . F. 1. 1 Perry SSER 2 1-5

Issue Status Section (42) Oesign for sampling and analysis of Awaiting plant effluents per TMI Action Plan information I tern I I. F. 1. 2 (43) Leakage surveillance preventive Changed to license maintenance program per TMI Action Condition (16) in Plan Item III.D.1.1 SSER No. 1 (44) Radiation/shielding design of IFTS Resolved 12.3.2 tube (45) Location of plant area radiation Resolved 12.3.4.1 monitoring per TMI Action Plan I tern I I. F. 1. 3 (46) Training program per TMI Action Plan Resolved 13.2.1.9 Item I I. B. 4 (47) Nuclear section training program Resolved 13.2.2.1 (48) Shift supervisor training per TMI Resolved 13.5.1.8 Action Plan Item I.C.3 (49) Verify implementation of rquipment Resolved 13. 5.1.11 control measures in radiation areas per TMI Action Plan Item I.C.6 (50) No load, light load, and test load- Resolved 9.6.3.1(4) ing of the diesel generators (51) NSSS vendor review of low-power Site confirmatory ascension, and emergency operating audit required to procedures per TMI Action Plan resolve .

(52)

Item I. C. 7 Pilot monitoring of selected emergency operating procedures per Awaiting information TMI Action Plan Item I.C.8 (53) Reactor internals vibration prototype Staff needs to 3.9.2.3 (BWR/6-238 in.) test program complete review of GE program adopted by CEI to resolve 1.11 License Conditions In Section 1.11 of the SER, the staff identified 15 license conditions. These included several issues that must be resolved by the applicant as a condition for issuance of an operating license, and other longer term issues (noted by an asterisk) that will be cited in the operating license issued, to ensure that NRC requirements are met during plant operation. License Condition (8) was deleted from this section and added to the list of confirmatory issues as Con-firmatory Issue (50) in Section 1.10 of SSER No. 1. This supplement adds License Condition {17), previously listed in Section 1.10 as Confirtftatory Issue (25),

and License Condition (18), 11 Control of heavy loads. 11 In addition, the staff has completed its generic evaluation of License Condition (2), which is addressed in Section 4.2.3.1 of this supplement.

Perry SSER 2 1-6

The updated and current list of license conditions, with references to appro-priate SER sections, follows:

(1) Implementation of protective measures when the Lake Erie shoreline recedes to 250 ft from the emergency service water pumphouse.*

(2) Periodic measurement of channel box deflections must be resolved before startup of the second cycle of operation - see Section 4.2.3.1 of this supplement for results of the staff's generic evaluation of this license condition.

(3) Operation beyond Cycle 1 not permitted until thermal-hydraulic stability analyses are provided for approval before Cycle 2 operation.*

(4) A final report analyzing inadequate core cooling implementation requirements per THI Action Plan Item II.F.2 should be submitted for staff approval.*

(5) Hydrogen control for degraded core accidents per TMI Action Plan Item 11.B.8 subject to completion of staff generic evaluation.*

(6) IE Bulletin 80-06, engineered safety feature reset control.

(7) Postaccident sampling system per TMI Action Plan Item 11.B.3.

(8) No load, light load, and test loading of the diesel generators - changed to Confirmatory Issue (50) in SSER No. 1 - is no longer at issue and will be deleted in future supplements to the SER (see Sections 1.10 and 9.6.3.1(4) of this supplement).

(9) Test data to demonstrate that the HPCS diesel generator will not experience undue wear at low room temperatures are to be submitted 24 months after fuel load.*

(10) Each operating shift shall be assigned a person with commercial BWR startup/

operating experience for a period of 1 year from fuel load, or the attain-ment of a nominal 100% power, whichever occurs later.*

{11) Test and maintenance procedures associated with engineered safety features per THI Action Plan Item II.K.1.15.

{12) Procedures for removing safety-related systems from service per TMI Action Plan Item II.K.1.10.

{13) Complete implementation and maintenance of staff-approved physical security, guard training and qualification, and safeguards contingency plans.*

(14) Initial test program per THI Action Plan Item I.G.1.

(15) Prohibition of extended cycle operation with partial feedwater heating.*

(16) Leakage surveillance and preventive maintenance program per THI Action Plan Item III.0.1.1.

Perry SSER 2 1-7

(17) ADS logic modification per TMI Action Plan Item II.K.3.18 - installation of approved modification is required before plant startup after the first refueling outage.*

(18) Before startup following the second refueling outage, the applicant shall have made commitments acceptable to the NRC regarding the guidelines of Sections 5.1.2 through 5.1.6 of NUREG-0612 {Phase II 110nth responses to the NRC generic letter dated December 22, 1980).

Finally, an additional Technical Specification item is being included to require the applicant to perform periodic surveillance tests and calibration of the low-pressure air alarm systems. This is discussed in Sections 6.3.1.3 and 16 of this supplement.

Perry SSER 2 1-8

3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, ANO COMPONENTS 3.9 Mechanical Systems and Components 3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment 3.9.2.3 Preoperational Flow-Induced Vibration lasting of Reactor Internals In Section 3.9.2.3 of the SER, the staff identified, as Outstanding Issue (3),

the reactor internals vibration test program for a prototype reactor (BWR/6-238 in.). The staff required that the applicant submit a prototype test pro-gram fully consistent with Regulatory Guide 1.20. The staff also required that the resolution of past boiling-water-reactor (BWR) problems be addressed by the applicant's test program.

It has been determined that the applicant adequately addressed the resolution of past BWR pro~lems such as the degradation of feedwater spargers, fuel box channel wear, and jet pump holddown beams (discussed in SER Sections 3.9.3.1, 4.2.3.1(5), and 3.9.5, respectively). The applicant's response regarding analytical predictions of internals vibration levels was addressed in a lett@r dated September 9, 1982 (0. R. Davidson to A. Schwencer), which included a draft copy of General Electric (GE) Topical Report NEOE-22203-P, entitled "Reactor Internals Vibration Predictions." The report describes the GE reactor internals vibration test program to be adopted by CEI and provides peak amplitude predic-tions obtained from engineering models and prototype reactor test data.

The staff has not yet completed its review of the GE report. Therefore, although the staff concludes that the applicant has satisfactorily responded to Regulatory Guide 1.20 in providing a complete prototype test program, this issue cannot be fully resolved until the staff completes its review of the GE report data applicable to Perry. On the basis of additional information pro-vided, Outstanding Issue (3), listed in Section 1.9 of the SER, is now con-sidered to be confirmatory and is being added to Section 1.10 of the SER as Confirmatory Issue (53) in this supplement. Its resolution will be addressed in a future supplement to the SER.

3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Support Structures 3.9.3.3 Component Supports In Section 3.9.3.3 of the SER, the staff identified the design of pipe whip restraints, which also function as a pipe support, as a confirmatory issue.

The applicant responded to this issue in a letter dated April 16, 1982 (0. A~

Davidson to A. Schwence1*), which identifies those r,straints that have a dual pipe whip restraint/support function, and which describes the boundary 4sed for determining its classification under Subsection NF,Section III of the AMerican Socie.ty of Mechanical Engineers, "Boiler and Pressure Vessel CQC,e" (ASME Code) and the American Institute of Steel Construction (AISC) building specification.

Perry SSER 2

The staff is currently developing a generic position on the classifications of auxiliary steel used as a pipe support (Subsection NF,Section III of the ASME Code) or building steel (AISC specification), as well a the plant inservice inspection requirements. The staff finds that the classification for the dual pipe whip restraint/support for the Perry design is consistent with currently accepted industry practices and with the generic position being developed by the staff. Therefore 1 Confirmatory Issue (9), listed in Section 1.10 of the SER, is considered to be resolved.

4 REACTOR 4,2 Fuel System Oe~ign 4.2.3 Design Evaluation 4.2.3.1 Fuel System Damage Evaluation (5) Dimensional Changes Channel Box Deflection (LRG-II Generic Issue 3-CPB)

The BWR fuel channels provide structural stiffness for the fuel assemblies and distribute the coolant flow between the assemblies and channel bypass regions.

The channels are subject to time-dependent, permanent dimensional changes (i.e.,

deflections) that result from irradiation, creep, and stress-relaxation effects.

The resultant bulge {caused by long-term thermal creep) or bow (caused by dif-ferential irradiation-induced axial growth) reduces the size of the gap avail-able for control rod insertion. Channel box deflection is thus a potential life-limiting phenomenon.

In Section 4.2.3.1(5) of the SER, the staff indicated that the issue of channel box deflection was resolved for Zimmer and other BWRs through the staff's accept-ance of the channel box surveillance plan proposed by the plants' licensees.

In a letter dated November 3, 1981 (0. G. Eisenhut to D. R. Davidson), the staff notified CEI of this and requested CEI to commit to the surveillance plan ap-proved for those plants. In a letter dated May 17, 1982 (D. L. Holtzscher to H. J. Faulkner), the Licensing Review Group-II (LRG-11), a group in which CEI is a participant, submitted a position paper (addressing LRG-II generic issue 3-CPB) on channel box deflection surveillance measures. This position and the survei 11 anee measures proposed ( adopted by CEI for Perry in a 1etter dated September 16, 1982) use several of the same surveillance measures approved by the staff for Zinuner and other BWR plants, name1y:

(a) Records will be kept of channel locations and exposure for each operation cycle.

(b) Channels shall not reside in the outer row of the core for more than two operating cycles (because flux gradients are largest near the core periphery, and, therefore, differential irradiation-induced growth and bowing will be greatest at those locations).

(c) At the beginning of each fuel cycle, the combined outer-row residence time for any two channels in any control rod cell shall not exceed four peripheral cycles.

• ln addition, channels that reside in the periphery (outer row) for more than cme c,yo 1e sha 11 be situated each success tve peri phera 1 eye 1e in a 1ocat ion that rotates the channel so that a different sid8 faces the core edge. The

... i

staff beli~ves that this should help to lessen channel bowing and that measures given in I~ems (a), (b), and (c) above would also help to reduce the magnitude of channe~ deflection.

The LRG-II position paper endorsed by CEI for Perry further provides a detailed description of the test program for the control rod drive settling function, which will be performed for any core cells that exceed the above measures, or which contain channels with exposures greater than 30,000 MWd/MTU (associated f**!:!1 bundle exposures).

The staff finds that CEI 1 s commitment to these LRG-Il measures and test program would preclude excessive channel bowing in Perry, and concludes that license Condition {2) pertaining to the need to periodically measure channel box deflec-tions before startup of the second cycle of operation has been satisfactorily addressed. These measures and test program will be appropriately cited in the operating license for Perry. The staff will continue to review this phenomenon generically with General Electric. Should the staff's generic findings war~ant further measures for application to Perry, CEI will be advised accordingly.

5 REACTOR COOLANT SYSTEM 5.3 Reactor Vessel Materials, Fabrication, 3nd Integrity 5.3.1 Re~ctor Vessel Materials (1) Compliance With Appendix G, 10 CFR 50 In Section 5.3.1(1) of the SER. the staff reported that it had reviewed the applicant's FSAR to determine the degree of compliance with the frac-ture toughness requirements of 10 CFR 50, Appendix G, and stated that the applicant was in compliance with Appendix G except for Paragraphs III.B.4 and IV.A.2.c. It was concluded that the applicant's proposed exemptions for performing tests in accordance with the written procedures of Para-graph 111.B.4 were justifiably supported, and that the applicant's proposed alternative to Paragraph IV.A.2.c to the criticality hydrostatic tempera-ture limit was also acceptable. Although not reported in the SER, the staff recognized that operating limits in accordance with Appendix G, Sec-tion Ill, of the ASME Code would not provide adequate safety margins for the Perry closure-to-flange and reactor vessel shell-to-flange disconti-nuities in accordance with Paragraphs IV.A.2.a and IV.A.2.b of Appendix G of 10 CFR 50.

Paragraphs IV.A.2.a and IV.A.2.b of Appendix G, 10 CFR 50, require, in part, that flange and shell regions near geometric discontinuities shall provide margins of safety in accordance with Appendix G,Section III, of the ASME Code. The applicant's fracture mechanics analysis indicates that operatiny li~its in excess of those required by Appendix G,Section III, of the ASME Code would be required for flaw depths great~~ than 0.24 in.

on the 01,tside surface of the flange-to-shel I joint. To satisfy this fracture mechanics evaluation the applicant has proposed either to:

(a) perform an augmented inservice examination of the flange-to-shell and head discontinuities that will detect flJws less than 0.24 in. on the outside surface, or (b) revise the pressure-temperature limits to provide margins of safety for the flange-to-shell and head discontinuities that are equivalent to those required by Appendix G,Section III, of the ASME Code.

The staff considers that an augmented inservice examination and/or revised pressure-temperature limits can provide adequate margins of safety for the flange-to-shell and head discontinuities.

The staff will assess the applicant's proposed inservice examination requirements for the flange-to*shell and head discontinuities and the revised pressure-temperature limits during its review of the applicant's inservice examination plan and NRC's Technical Specification to ensure that s~fety margins. equivalent to those of Appendix G,Section III, of the ASME Code, are met.

(2) Compliance With Appendix H, 10 CFR 50 In Section 5.3.1(2) of the SER, the staff reported on its review of the applicant's compliance with 10 CFR 50, Appendix H, concluding the appli-cant's noncompliance wit~ Paragraph 11.B of Appendix H to be a confirma-tory issue. Specifically, Paragraph 11.B requires that the applicant's surveillance program comply with American Society for Testing and Materials (ASTM) E-185-73. ASTM E-185-73 requires that the materials in the sur-veillance capsules be removed from reactor vessel beltline base metals and weld metal samples that will be limiting for operation of the reactor vessel during its lifetime. At the time the SER was issued, the appli-cant's FSAR amendments through Amendment 6 had not reported the weld metal in the surveillance program.

In a letter dated September 22, 1982 (D. R. Davidson to A. Schwencer), the applicant identified the weld material in the Perry plant surveillance pro-gram. The staff's review of the surveillance program weld material indi-cates that the material is representative of the limiting reactor vessel beltline weld metal and satisfies the surveillance program requirements of Paragraph 11.B of Appendix H. Thus, Confirmatory Issue (16), listed in Section 1.10 of the SER, is considered to be resolved.

Perry SSlR 2 5-2

6 ENGINEERED SAFETY FEATURES 6.2 Containment Systems 6.2.1 Containment Functional Design 6.2.1.9 Secondary Containment For Perry, the secondary containment structure consists of the shield building, which is a cylindrical reinforced concrete structure that completely surrounds the containment. The secondary containment is used to control and treat radio-active leakage from the primary containment in the event of a loss-of-coolant accident (LOCA). Although the primary containment is enclosed by the secondary containment, there are systems that penetrate both the primary and secondary containment boundaries creating potential leakage paths, in the event of a LOCA, through which radioactivity in the primary containment could bypass the leakage collection and filtration systems associated with the secondary contain-ment.

In Section 6.2.1.9 of the SER, the staff found that the applicant had not suf-ficiently considered leakage from lines that penetrate the primary and secondary containment, believed to be potential bypass leakage paths. The staff con-sidered this to be a confirmatory issue and required the applicant to justify their exclusion from leakage consideration.

In a letter dated June 7, 1982 (0. R. Davidson to A. Schwencer), the applicant addressed this issue and provided the criteria the applicant used to determine and assess potential bypass leakage paths. These criteria showed that the penetration lines in question were excluded because they contain physical bar-riers or design provisions (e.g., the lines contain water seals, they involve closed Category I piping systems, and/or leakage controls are provided in the design) that will effectively eliminate leakage. Where relied on to eliminate leakage, these provisions are designed to (1) meet the single-failure criteria, (2) be missile protected, and (3) have a temperature and pressure rating in excess of that for containment.

The staff finds that the additional information furnished by the applicant suf-ficiently justifies exclusion of these lines from bypass leakage consideration in that the physical barriers and design provisions identified will essentially eliminate any leakage and are consistent with the acceptance criteria of Branch Technical Position CSB 6-3~ "Determination of Bypass Leakage Paths in Dual Con-tainment Plants." Therefore, Confirmatory Issue (22), listed in Section 1.10 of the SER, is considered to be resolved.

6.2.3 Containment Isolation System This issue was inadvertently omitted from the list of confirmatory issues con-tained in Section 1.10 of the SER and is accordingly addressed below.

Perry SSER 2 6-1

The containment isolation system includes the containment isolation valves, associated piping, and penetrations necessary to isolate the primary contain-ment in the event of a LOCA. In Section 6.2.3 of the SER, the staff reported that the containment isolation provisions in the Perry design, for lines pene-trating containment, conformed with the requirements of General Design Criteria

{GOC) 55, 56, and 57 {10 CFR 50, Appendix A), as appropriate. However, the ap-plicant had not adequately correlated all of the proposed deviations from the explicit requirements of GOC 55 and 56. (As indicated in these GOCs, there are containment penetrations whose isolation provisions do not have to satisfy the explicit requirements specified therein, but can be accepted on some other de-fined basis, e.g., the use of the alternative criteria in Section 6.2.4 of the Standard Review Plan {NUREG-0800)). The need for a clear correlation of the criteria usqd was considered to be a confirmatory issue by the staff.

In a letter dated June 7, 1982 {D. R. Davidson to A. Schwencer), the applicant furnished additional information that can distinguish isolation provisions in the plant that explicitly meet GDC 55 and 56 1 as well as those for which the alternative criteria in Section 6.2.4 of NUREG-0800 are appplicable. The appli-cant's treatment of these criter* a are summa*-*i zed as fo 11 ows:

{1) Lines that must remain i1, service following an accident and lines that must remain in service during normal operation for safety reasons are provided with at least one isolation valve. A second isolation boundary is formed by a closed system outside the containment.

{2) Where a closed system outside the containment forms the second isolation boundary, each of the systems and all components that form its boundary are designed to Quality Group Band seismic Category I standards. Valves that isolate the branch lines of these closed systems outside containment are normally closed and under strict administrative control.

{3) On certain engineered safety features or related system, remote manual valves are used instead of automatic valves, since these lines must remain in service following an accident. Where remote manual valves are used, leakage-detection capabilities are provided.

(4) On some penetrations, the containment isolation provisions consist of two valves in series, both of which are outside the containment. For these penetrations, locating one of the valves inside containment would subject it to more severe environmental conditions (including suppression pool dynamic loads) than if it were outside containment; moreover, the inside valve would then not be easily accessible for inservice inspection.

On the basis of the additional information provided by the applicant and sum-marized above, the staff finds that the applicant satisfactorily correlates criteria used for the Perry containment isolation system design and concludes that this confirmatory issue is resolved.

6.2.6 Containment Leakage Testing The staff reviewed the applicant's containment leak-testing program for com-pliance with the containment leak-testing requirements specified in Appendix J to 10 CFR 50. Such compliance provides adequate assurance that the leak-tight Perry SSER 2 6-2

integrity of the containment can be verified throughout the service lifetime and that the leakage rates will be periodically checked during service on a timely basis to maintain such leakage within the specified limits. Maintaining containment within such limits provides reasonable assurance that in the event of any radioactivity release within the containment, the loss of the contain-ment atmosphere through potential leak paths will not be in excess of the limits specified for the site.

In its review of the applicant's leak-test program (as reported in Section 6.2.6 of the SER), the staff found that the applicant's test progr~m ensures that con-tainment penetrations and system isolation valve arrangements are designed to satisfy the containment integrated leak rate and the local leak-testing require-ments of 10 CFR 50, Appendix J, in that the program will include an ASME Code Type C test of all emergency core cooling system injection valves with air, unless it can be demonstrated that a water seal exists that meets the sing1e-failure criteria. However, the applicant was asked, as a confirmatory issue, to incorporate the following additional provisions in the containment leak-test program:

(1) All isolation valves listed in Table 6.2-40 of the test program should be Type C tested.

(2) The feedwater lines (test items 9 and JO) should be vented and drained for a Type C test, tested in air, and the ieakage included in 0.60 La.

(3) High-pressure core spray (HPCS) pump disL~~rg~ to the reactor vessel (test item 32) and the low-pressure core spray (LPCS) pump discharge to the reac-tor vessel (test item 35) should be tested with air and the leakage included in 0.60 La (60% of maximum allowable leakage rate at pressure Pa, which is the calculated peak containment pressure).

In a letter dated June 8, 1982 (D. R. Davidson to A. Schwencer), the applicant responded to this confirmatory issue as follows:

(1) All containment isolation valves listed in Table 6.2-40 of the test program will be Type C tested except for the instrument line isolation valves that penetrate the containment and that conform to Regulatory Guide 1.11. Isolation valves, pressurized by a water seal system, will be consistent with the Type C test acceptance criteria in Appendix J.

Examples of such l'ines are discussed in (2) and (3) below, and are lines that terminate below the water level of the suppression pool. Sufficient pool inventory is available to maintain a 30-day pressure at 1.10 Pa.

The pipinV up to each isolation valve is seismic Category I, Safety Class 2 piping - missile and pipe whip are not concerns for this piping.

(2) The feedwater lines will be Type C tested with water and the leakag~ will not be included in the 0.60 La. This is consistent with the Appendix J acceptance criteria because a dedicated feedwater leakage control system is provided for these lines.

(3) HPCS, LPCS, and low*pressure coolant injection pump discharge lines to the reictor vessel will be Type C tested with atr, and the largest ltakage Perry SSER 2 6-3

included in 0. 60 La. Consistent with Appendix J acceptance criteria hydro ..

static testing may be performed if a Hquid inventory to maintain a water seal is demonstrated, assuming single failure of any active component.

The staff finds this response to be acceptable, and that the applicant's containment leak-test program wi 11 meet the criteria of Appendix J. Confirma-tory Issue (24), listed in Section 1.10 of the SER, is accordingly resolved.

6.2.7 TMI-2 Requirements (3) Containment holation Dependability (TMI Action Plan ltE:,n II.E.4.2)

Discussion and Conclusion In Section 6.2.7(3) of the SER, the staff evaluated the applicant's CQlllpliance with the TMI Action Plan Item II.E.4.2 (NUREG-0737) requirements and identified, as a confirmatory issue, the need for the applicant to classify essential and nonessential systems in regard to the containment isolation system - Item (b) -

and to specify the minimum containment pressure setpoint that will be compatible with normal operating conditions - Item (e). The applicant provided additional information in a letter dated June 8, 1982 (D. R. Davidson to A. Schwenc,r),

which acceptably classified the systems penetrating containment into essential and nonessential systems, indicating the essential systems to be engineered safety features systems that are required for accident situations or shutdown, and which stated that the minimum containment pressure setpoint, still being determined, would be provided and reviewed in connection with the preparation of the NRC Technical Specification for Perry.

The staff considers this response to be acceptable to fully meet the require-ments of TMI Action Plan Item II.E.4.2 and that Confirmatory Issue (23), listed in Section 1.10 of the SER, is resolved.

6.3 Emergenc~ Core Cooling S~stem (ECCS}

6.3.1 System Description 6.3.1.3 Funct1onal Design Requirement In Section 6.3.1.3 of the SER, the staff reported, as part of its review and evaluation of the Perry ECCS functional design, that the automatic depressuri-zation system (ADS) CEI is planning to incorporate can be used as a b*ckup to the high-pressure cooling systems and allows the functioning of the low-pressure cooling systems in the event of a small-line break. The air supplied to the ADS valves will be provided in accident conditions by seismically qualifie~

accumulators and receivers to compensate for leakag, 1;uJst acctUnulator ch.eek valves in accordance with TMI Action Plan Item U.K.3.28 requirements. Air or nitrogen accumulators for the ADS valves are provided with $1.tfficient c4pacity to cycle the valves open five times at destgn pressure~. The Ger,e1*al Eh,ctric Company has also stated that the ECCS is de& i gntd to with$ tand c,1 t,O$ t He erw i ..

ronment and still perform its function within 108 dc1ys following an ac(ident.

Discuss ion The staff required that the applicant demonstrate that the ADS valves, accumula-tors, and asssociated equipment and instrumentation meet the requirements of TMI Action Plan Item II.K.3.28 and are capable of performing tiu,i, intended functions during and following exposure to hostile environments, taking no credit for nonsafety-related equipment or instrumentation. Additionally, air (or nitrogen) leakage through valves must be accounted for to ensure th~t enough inventory of compressed air is available to cycle the ADS valves. If this cannot be demon-strated, it must be shown that the accummulator design is still acceptable.

The applicant's commitment to satisfy the requirements of TMI Action Plan Item II.K.3.28 is discussed in the Licensing Review Group-II (a group formed to address BWR/6 issues on a generic basis) position paper submitted by letter from 0. L. Holtzscher (Illinois Power Company) to H. J. Faulkner (NRC) dated May 17, 1982. The ADS design described in the position paper is identified as Generic Issue 8-RSB. In a letter dated September 16, 1982 (D. R. Davidson to A. Schwencer), CEI as a member of the Licensing Review Group-II (LRG-II) adopted the LRG-II position regarding the ADS design for Perry, which is described below.

Design Description The ADS design described in the LRG-11 position paper, and adopted for Perry by CEI, uses selected safety/relief valves (SRVs) for depressurization of the reactor. Each SRV utilized for automatic depressurization is equipped with an air accumulator, a check valve, and a safety-grade backup air supply. The safety--grade ADS pneumatic supply is separated into two divisions. The loss of air supply to one division of ADS valves will not prevent the ability of the ADS to depressurize the reactor system if it is required. The ADS accumu-lators are designed to provide two SRV actuations at 70% of drywell design pressure, which is equivalent to four actuations at atmospheric pressure.

Normal air is supplied for the ADS valve accumulator from an air compressor located in the Perry auxiliary building. This compressor supplies air to two inline air receiver tanks located in the Perry intermediate building, each having a volume of 10.5 ft 3

• The compressor automatically maintains air pres-sure in these two tanks between 2,250 and 2,500 psig. Each tank serves one division of ADS valve accumulators by means of a 2,500/150-psig pressure regu-lating valve. If the air compressor is not available, the compressed air in the two inline receiver tanks serves as the backup air supply and can recharge the ADS valve accumulators to provide makeup for any system leakage for a period of 7 days. Both tanks have a connectivn on downstream piping to permit com-mercially available air or nitrogen bottles to be connected to the system to ensure a 100-day postaccident ADS air supply.

The ADS air supply system, from the two inline check valves *1ocated upstream of each air receiver tank to the valve accumulators, is designed to the requirements of ASME Code,Section III, Class 3, and is seismic Category I.

The section of this line penetrating the containment and the inboard and outboard isolation valves are designed to the requirements of ASME Code,Section III, Class 2, and are seismic Category I.

In the event of a loss of air supply from the air compre1sor, one or more of the following control room ~larms would be activated:

Perry "SER 2 6-5

. . .. '- ... ', ~*

(1) receiver tank air pressure low (2,000 psig)

(2) air compressor/purifier package inoperable When the alarm in the control room indicates low receiver tank pressure, the air compressor is manually started and runs until the syrtem pressure is re-turned to the normal operating range. When the alarm indicates the compressor is inoperable, receiver tank pressure is monitored while the compressor problem is evaluated. If the compressor cannot be restarted in a timely fashion, then commercially available air or nitrogen bottles can be connected to the safety-class connections near the air receiver tank to supplement the tank's supply during repairs. The connections for the air or nitrogen bottles are located outside the reactor building in the auxiliary building or the control complex and are accessible in the event of an accident.

Evaluation The staff has evaluated the LRG-II position paper design adopted for Perry by CEI and finds that the ADS backup air supply system has been designed for sufficient inventory to cycle the ADS valves in the event they are required to operate. In addition, the large receivers will be monitored in the control room to ensure there is sufficient inventory of air to cycle the ADS valves according to design requirements. If the air receivers* inventory drops below 2,000 psig, and the air compressor is not available to restore the receiver pressure to between 2,250 and 2,500 psig, additional air can be provided by remote bottle h0okups.

The following surveillance requirements will be incorporated into the NRC Technical Specifications to ensure the Perry backup air system will provide continued long-term assurance of the availability of sufficient inventory of air to actuate the ADS valves if they are needed:

(1) At least once every 31 days, perform a channel functional test of the accumulator backup compressed gas system low-pressure alarm systems.

(2) At least once every 18 months, perform a channel calibration of the

~ccumulator backup compressed gas system low-pressure alarm systems and verify the air alarm setpoint of 2,000 ! 75 psig on decreasing pressure.

This periodic surveillance of the low-pressure alarm system, in conjunction with the design of the backup air supply systems to the ADS valves, should ensure an adequate and operable backup air supply to the ADS valves in the event they are required to operate. The staff, therefore, concludes that the LRG-II position design adopted for Perry by CEI is acceptable and will meet the requirements of TMI Action Plan Item II.K.3.28.

6.4 Control Room Habitability Systems In Section 6.4 of the SER, the staff considered control room habitability acceptable for meeting TMI Action Plan Item III.0.3.4 and GDC 19. However, in a separate review of the control room fire protection systems, as reported in Section 9.5.1.6.2 of the SER, the staff was concerned that the use of a carbon dioxide (CO 2 ) fire extinguishing system in the underfloor spaces of the control room could jeopardize the habitatility of the control room. In a Perry SSfR 2 6-6

letter (D. R. Davidson to A. Schwencer) dated August 31, 1982, the applicant provided further details of the CO 2 system and the consequences of its use.

The fire extinguishing sytem is designed to discharge CO 2 in short bursts into any of three subfloor zones where there is a fire and repeat this process if reignition occurs.

The staff has reviewed the potential consequences of the eventual entry of CO 2 and other gases produced by combustion into the control room atmosphere, and, in light of the additional information furnished by the applicant, has conclud-ed that these gases do not jeopardize the habitability of the control room. In the ca~e of a lingering fire requiring multiple discharges from the system, discharges over tens of minutes would be required before unhealthy concentra-tions of CO 2 and pyrolysis gases would accumulate in the control room. Because the system automatically alarms within the control room, adequate time is avail-able for personnel to don self-contained breathing apparatuses supplied for this purpose. The total amount of CO 2 (1,000 lb) is capable of displacing approximately 3% of the 268,000-ft 3 free volume of the control room envelope.

The current permissible 8-hour shift exposure to CO 2 is 0.5% (as specified in the Occupational Safety and Health Act (OSHA) National Institute of Occupa-tional Safety and Health (NIOSH) Publication 81-123, 1981), which was adopted from the existing industry standard. NIOSH has recommended limits of 1% CO 2 exposure averaged over 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> per week and 3% for routine exposures of less than IO-minutes duration. The amount of CO 2 in standard air is 0.04%, in urban air it is often as high as 0.1%, and in human exhalation it is approximately 5%. Self-contained breathing apparatuses are required by OSHA for work places having concentrations of 5% or more. Concentrations as high as 1.5% are per-mitted in submarines and space craft (American Industrial Hygienists Associa-tion, Hy~ienic Guide). Should the entire CO 2 inventory of the system be dis-charged 1nto the control room envelope while it is isolated from outside air, it is recommended that the operators don self-contained breathing apparatuses to reduce the likelihood of minor effects such as labored breathing or delayed headaches, but such action would not be required to prevent incapacitation.

The control room smoke purge system has the capacity, if manually initiated, for exchanging 10% per minute of the control room air volume with the outside atmosphere, or reducing excess CO 2 concentrations by half every 7 minutes.

As a consequence of the above considerations, the staff concludes that use of the CO 2 fire extinguishing system is acceptable with respect to control room habitability. This evaluation finding, together with tha+ presented in Sec-tion 9.5.1.6.2 of this supplement, resolves Outstanding Issue (16) listed in Section 1.9 of the SER.

Perry SSER 2 6-7

7 INSTRUMENTATION AND CONTROLS

7. 2 Re_~ctor Protect ion Systems 7.2.2 Specific Findings 7.2.2.4 Scram Discharge Volume Level Monitoring System The staff reported in the SER that, as a result of the Browns Ferry event, where a complete insertion of the control rods was not successful until several at-tempts had been made, the applicant had modified the design of the scram dis-charge instrument volume level monitoring system to preclude such an event occur-ring in Perry. Although the staff found the modified design acceptable, the applicant was required, as a confirmatory issue, to provide a complete descrip-tion of the modified design in the FSAk. In a letter dated October 25, 1982 (D. R. Davidson to A. Schwencer), the applicant provided documentation to be included in a future FSAR amendment that the staff finds acceptably describes the modified design approval. Therefore, Confirmatory Issue (27), listed in Section 1.10 of the SER, is resolved.

7.3 Engineered Safety Features (ESF) Systems 7.3.2 Specific Findings 7.3.2.2 High-Pressure Core Spray System In the SER the staff reported its evaluation of the Perry high-pressure core spray (HPCS) system initiation circuitry design including its concurrence with the applicant's argument that a high d~.vwell pressure interlock, which the staff had found was needed to prevent premature termination of HPCS, be excluded.

(The applicant had maintained that the interlock would tend to keep HPCS in operation past the point necessary to reflood the core, causing steamline flood-ing, and that addition of the interlock would not significantly increase the overall safety of the plant.) Although the staff found the design, excluding the interlock, acceptable, it required the applicant, as a confirmatory issue, to formally submit the revised system design for review and to incorporate the revised design in the plant before start of operation. The applicant provided the final design approved by the staff in a letter dated October 14, 1982 and committed to incorporate the design before start of plant operation. The staff has confirmed that the final design provided in that letter is acceptable, thus resolving Confirmatory Issue (28), listed in Section 1.10 of the SER. A confirm-atory site audit of the HPCS initiation circuitry design will be conducted before fuel load of Unit 1 to verify that the final design acceptable to the staff has been installed.

7.3.2.6 Periodic Testing of ESF Actuation Systems During Plant Operation During the staff's review of the capability to test the pilot solenoid valves that control compressed air to the automatic depressurization system (ADS)

Perry SSER 2 7-1

relief valves, it became apparent that the present Perry design does not pro-vide a feature to test the solenoid valves and associated circuitry with the plant at power. In the GESSAR-238 nuclear steam supply system preliminary de-sign SER (Docket No. STN 50-550), dated March 1977, the staff identified this as a potential problem and took the position that GE would be required to make provisions to improve the testability of the ADS solenoid valves during reactor operation.

The staff continued to pursue with the applicant the adequacy of the ESF actua-tion system design from the standpoint of providing the capability to periodi-cally test the actuation circuits with the plant at power. In a letter from the applicant dated April 29, 1982 (D. R. Davidson to A. Schwencer) and in a subsequent meeting, this issue was discussed. The applicant described the capa-bility of testing ESF systems at power. For example, it is possible to test portions of the circuitry to energize a pump while maintaining the injection valve closed and subsequently test the injection valve while maintaining the pump deenergized.

This capability exists for all ESF systems except the ADS. The ADS is unique in that the ADS solenoid valves cannot be tested without causing the safety/

relief valves to open. The applicant stated that the ADS pilot solenoid oper-ability test is performed at least once every 18 months at a reduced reactor steam dome pressure. GE has investigated the benefit of adding valves to test the ADS pilot solenoid valve at power and has concluded (letter, G. G. Sherwood to B. C. Rusche, August 9, 1976) that those modifications that would permit full ADS solenoid valve testing would decrease the reliability of the ADS. It should be noted that redundant solenoid valves operated from redundant divi-sions are provided for each ADS valve. The applicant has also investigated continuity checks of the solenoid valve at power and has stated that there is no reason to believe and no experience to indicate that continuity of the sole-noid valve is questionable while the rest of the ADS is operable. Furthermore, the applicant states that given the proven reliability of the solenoid valve, the weakest link is more probably the mechanical motion of the solenoid plunger, which the continuity check would not verify. As a result of GE's and the appli-cant1s investigations, it is apparent to the staff that to modify the current ADS design to include an additional continuity check of the solenoid valve will only slightly improve the proven reliability of the ADS pilot solenoid valve.

Therefore, the staff has concluded that the addition of a continuity check for the ADS solenoid valves would not improve the reliability of the ADS suffi-ciently to justify the complexity of the required check.

In addition, the staff has concluded that the current surveillance test interval for the ADS pilot solenoid valve (at least once every 18 months) and the monthly ADS logic testing, which tests through the relay contacts in the valve solenoid circuit and causes a panel light to come on indicating proper channel operation, are sufficient. These intervals for testing have been established and approved by the staff for operating BWRs. This resolves Outstanding Issue (11) listed in Section 1.9 of the SER.

7.3.2. 7 Manual Initiation and Termination of ESF Systems During its review of the ESF systems, the staff found that the logic for manual initiation for several ESF systems is interlocked with permissive logic fro*

Perry SSER 2 7-2

various sensors. In some cases it appears that the permissive logic is depend-ent on the same sensors as those used for automatic initiation of the system.

The staff questions whether this design meets the intent of Institute of Elec-trical and Electronics Engineers Standard 279, Section 4.17.

The staff still considers Outstanding Issue (12) in Section 1.9 of the SER to be unresolved and is continuing to pursue with the applicant the adequacy of the design for manually initiating and terminating safety systems at the system level. In a letter dated July 20, 1982 (D. R. Davidson to A. Schwencer), the applicant provided additional information that lists the ESF systems in which the logic for manual initiation is interlocked with permissive logic from var-ious sensors. The applicant has also provided justification for the presence of these permissive interlocks. The staff is currently reviewing this informa-tion and will report its findings on this issue in a future supplement to the SER.

7.4 Systems Required for Safe Shutdown 7.4.2 Specific Findings 7.4.2.2 Remote Shutdown System The applicant had indicated that several of the readouts and associated sensors and power supplies on the remote shutdown panel were not safety grade. The applicant has reviewed the design to determine whether these nonsafety-grade readouts and associated sensors and power supplies are required to achieve shut-down. The results of this review (letter dated April 29, 1982 from D. R. David-son to A. Schwencer) have indicated that all of the readouts and associated sensors and power supplies that are required to achieve shutdown are safety grade. The staff concludes that this confirmatory issue is resolved and that the design of the remote shutdown system is in conformance with the applicable criteria and is, therefore, acceptable. This resolves Confirmatory Issue (29) listed in Section 1.10 of the SER.

7.4.2.4 RCIC Test Procedures On the basis of its review of the reactor core isolation cooling (RCIC) test procedures furnished by the applicant, and reported in Section 7.4.2.4 of the SER, the staff found that they demonstrated that the RCIC system can be tested adequately during plant operation and were therefore acceptable. However, the staff noted several minor discrepancies between the RCIC system logic, as shown on an electrical-elementary diagram (B-208-075, System E51), and the test pro-cedures, which the staff required the applicant to correct as a confirmatory issue. In a letter dated October 14, 1982, the applicant confirmed that the discrepancies were evident and committed to correct all of the diagrams to be consistent with the procedures accepted by the staff. The staff finds that the applicant's commitment satisfactorily addresses this issue. Therefore, Con-firmatory Issue (30), listed in Section 1.10 of the SER, is resolved.

Perry SSER 2 7-3

7.5 Safety-Related Display Instrumentation 7.5.2 Specific Findings 7.5.2.5 Additional Accident-Monitoring Instrumentation (TMI Action Plan Item II.F.1, Positions 4, 5, and 6)

In reviewing the applicant's conformance with the requirements of TMI Action Plan Item II.F.1, Positions 4, 5, and 6 (II.F.1.4, II.F.1.5, and 11.F.1.6), the staff found that the containment pressure monitor, the containment water level (suppression pool) monitor, and the containment hydrogen monitor, described in the applicant's letter dated April 20, 1982, appropriately provide redundant, seismically and environmentally qualified instrumentation, powered from reli-able power sources, and found to be of suitable range. However, the staff re-quired, as a confirmatory issue, that the applicant define the accuracy of the monitors to be used at Perry to determine full conformance with TMI Action Plan Items II.F.1.4, 11.F.l.5, and 11.F.l.6. The applicant provided this information in a letter dated October 14, 1982. The accuracy of the monitors is considered to be acceptable to the staff. Therefore, Confirmatory Issue (32), listed in Section 1.10 of the SER, is resolved.

7. 7 Control Systems

7. 7.2 Specific Findings

7. 7.2.3 Failures in Vessel Level Sensing Lines Common to Control and Protection Systems (LRG-II Generic Issue 1-ICSB)

In Section 7.7.2.3 of the SER, the staff reported its findings regarding an analysis performed by the Licensing Review Group-II (LRG-II), and adopted for Perry by CEI, which generically addresses a break in a level sensing line com-mon to reactor control and protection systems. The LRG-11 analysis considered a combination of the worst-possible failure in a protective channel. The staff concluded that although the LRG-II analysis was predicated on a 251-in.-core-diameter BWR/6 plant, the results were applicable to the Perry 238-in. core diameter because the plant size characteristics analyzed were found to be con-servative, in that the water level in the core would not be lower for Perry and that the scenario postulated in the LRG-II analysis would have no adverse safety consequences. However, in describing the applicability of the LRG-II findings to Perry, the applicant indicated that when the recirculation pumps trip off, they would be transferred to the low frequency motor generator sets, which the staff found to be inconsistent with the LRG-II analytical results. The appli-cant was required to confirm the basis for this inconsistency as a confirmatory issue. In a letter dated October 14, 1982 (D. R. Davidson to A. Schwencer),

the applicant responded that it was in error and that the pumps would not trans-fer to the motor generator sets after tripping off. The staff considers this response acceptable and consistent with the LRG-II findings. Thus, Confirma-tory Issue (33), listed in Section 1.10 of the SER, is resolved.

Perry SSER 2 7-4

8 ELECTRIC POWER SYSTEMS 8.2 Offsite Power Systems 8.2.4 Adequacy of Station Electric Distribution System Voltages In Section 8.2.4 of the SER, the staff reported the results of its evaluation of the Perry design for conformance with Branch Technical Position (BTP) PSB-1, "Adequacy of Station Electric Distribution System Voltages." The staff required, as a confirmatory issue, that the applicant provide the final design of the first and second level undervoltage protection of the safety equipment in accordance with BTP PSB-1 before plant startup.

The applicant provided details of the final design in a letter dated August 26, 1982 (D. R. Davidson to A. Schwencer). The design provides three redundant and independent emergency buses, each having two levels of undervoltage protection:

(1) loss of power and (2) degraded grid voltage. The loss of power protection at the 4.16-kV emergency buses consists of two sets of three single-phase instan-taneous undervoltage relays with a setpoint at 75% of the equipment rated volt-age. The relays are arranged in a two-out-of-two coincident logic to initiate a timer with a 3-sec time delay. In the event that voltage loss is maintained for 3 sec, the timer trips the offsite power source breakers and will initiate the necessary logic to start the diesel generators and connect the Class IE buses to the diesel generators.

The degraded grid voltage protection at the 4.16-kV emergency buses consists of two sets of three single-phase instantaneous undervoltage relays with a set-point at 96% of the equipment rated voltage. The relays are arranged in a two-out-of-two coincident logic to initiate two separate time-delay relays. The first time-delay relay will initiate undervoltage alarms after 15 sec. If an undervoltage condition between 96% and 75% occurs, concurrent with a LOCA, the emergency bus is retained on offsite power for a IS-sec time delay, after which the offsite source breakers will be tripped and the diesel generator will supply power to Class lE loads through the load sequencer. The second time delay will be set for 5 minutes at which time the offsite source breakers will be tripped and the diesel generator will energize the emergency bus. The Class IE equip-ment (motors) is capable of starting ~nd accelerating its specified load with 75% of rated voltage at the equipment te,niinals. The 5-minute timer will also ensure against the motors' overheating between 90% and 75% voltage.

The staff finds that the applicant's final design of the first and second level undervoltage protection of safety equipment is acceptable; thus, Con-firmatory Issue (34), listed in Section 1.10 of the SER, is satisfactorily resolved.

Perry SSER 2

9 AUXILIARY SYSTEMS 9.1 Fuel Storage Facility 9.1.5 Overhead Heavy-Load-Handling System In Section 9.1.5 of the SER, the staff stated that the applicant had committed to implement the interim actions before the final implementation of the NUREG-0612 guidelines and before the operating license is issued. Additionally, the applicant, by letter dated September 15, 1982, committed to full compliance with the guidelines of NUREG-0612. The applicant has made three submittals dated June 19, 1981, June 9, 1982, and September 15, 1982, concerning the imple-menta' ion of Phase I of NUREG-0612. The staff's review of the applicant's sub-mittals is continuing. However, the staff will require that a condition be placed in the license requiring that before startup following the first refuel-ing outage, the applicant shall comply with the guidelines of Section 5.1.1 of NUREG-0612 (Phase I - the 6-month response to the NRC generic letter dated December 22, 1980). Before startup following the second refueling outage, the applicant shall have made commitments acceptable to the NRC regarding the guide-lines of Sections 5.1.2 through 5.1.6 of NUREG-0612 (Phase II month responses to the NRC generic letter dated December 22, 1980).

9.3 Process Auxiliaries 9.3.4 Standby liquid Control System In a letter dated August 13, 1982 (0. R. Davidson to A. Schwencer), the appli-cant summarized a change in the design of the standby liquid control system that includes an increased flow capacity from 43 gpm to 86 gpm. This will in-volve increasing the size of both pumps' suction lines as well as changing the reactor vessel injection point to the high-pressure core spray system header.

Although the design will include both manual and automatic initiation capa-bility, only manual initiation will be functional. Details of the design change will be documented by the applicant in a future amendment to the appli-cant's FSAR.

The planned design change is still considered to be an outstanding issue pend-ing staff review of the final design details. The staff's evaluation findings on this issue will be addressed in a future supplement to the SER.

9.5 Fire Protection Systems 9.5.1 Introduction 9.5.1.4 General Plant Guidelines 9.5.1.4.2 Safe Shutdown Capability In Section 9.5.1.4.2 of the SER, the staff considered, as an outstanding issue, the need for the applicant to provide a satisfactory analysis of the plant fire Perry SSER 2 9-1

protection features that ensure safe shutdown capability in accordance with Branch Technical Position CMEB 9.5-1, Section C.6.b (10 CFR 50, Appendix R, Section III G). In a letter dated June 16, 1982 (D. R. Davidson to A. Schwencer),

the applicant addressed this issue and identified several plant areas that deviate from the equipment separation requirements of Appendix R,Section III G.

The staff has reviewed this information and finds (1) that the analysis per-formed by the applicant will ensure that the plant fire protection measures will meet requirements and (2) that protection measures to be taken in those areas that deviate from the provisions of Appendix R,Section III G, are accept-able in protecting equipment needed for safe shutdown. The applicant was advised of the resolution of this issue (identified as Outstanding Issue (15) listed in Section 1.9 of the SER) in a letter from A. Schwencer to 0. R. Davidson dated November 26, 1982. A more comprehensive documentation of the staff's findings and basis for accepting the proposed deviations to Appendix R will be provided in a future supplement to the SER.

9.5.1.6 Fire Protection of Specific Plant Areas 9.5.1.6.2 Control Room In Section 9.5.1.6.2 of the SER, the staff considered, as an outstanding issue, the use of carbon dioxide (CO 2 ) as a fire suppression agent in the control room.

The staff reported that (1) CO 2 had not been tested and approved as a fire sup-pressant in the GE power generation control complex (PGCC) system selected for installation in the plant; (2) GE Topical Report NED0-10466, Revision 2, dated March 1978, which pertains to the selected PGCC system, and approved by the staff, specifies that Halon 1301 fire protection is required; and (3) there were concerns that CO 2 might leak from the PGCC underfloor into the control room (e.g., because of an inadvertent activation of the system) resulting in possible injury to the operators and the forced evacuation of the control room.

In response to an appeal from the applicant for the staff to reconsider its objection to the CO 2 system, the staff's specific concerns were detailed in a letter dated June 9, 1982 (A. Schwencer to D. R. Davidson). In a letter dated August 31, 1982, the applicant addressed each of the staff's concerns and pre-sented details of planned system design modifications that reduce the amount of CO 2 that could be hazardous to the operators, while at the same time providing effective fire suppressant capability.

The staff has reviewed the applicants* responses and evaluated the planned de-sign modifications; it finds that its concerns regarding the use of CO 2 have been satisfactorily addressed, and that the modified system design will pre-clude impairment of the operator's ability to maintain safe shutdown conditions from the control room in the event of a fire or because of an inadvertent dis-charge of CO 2

• The resolution of this issue, identified as Outstanding Issue (16) in Section 1.9 of the SER, was communicated to the applicant in a letter from A. Schwencer to D. R. Davidson dated November 26, 1982. A more detailed and comprehensive documentation of the staff's fire-protection review findings and basis for accepting the CO 2 system instead of the required Halon 1301 system in the control room PGCC system will be provided in a future supplement to the SER.

Perry SSER 2 9-2

9.6 Other Auxiliary Systems 9.6.3 Emergency Diesel Engine Fuel Oil Storage and Transfer System 9.6.3.1 Emergency Diesel Engine Auxiliary Support Structures (General)

(4) Testing No-Load and Light-Load Operation In Section 8.3.1 of the FSAR, the applicant discussed the manufacturer's recom-mendations for no-load and light-load operation of the diesel generators. In a letter dated March 25, 1982, the applicant committed to implement the following procedures before startup:

(a) Whenever a diesel is started and operated for an extended period of time (that is, not terminated within 2 minutes), the diesel generator shall be loaded to at least 25% of full load for a minimum of 30 minutes.

(b) During periodic testing, the diesel will be loaded to a minimum of 25%

of full load or as recommended by the manufacturer.

(c) During trouhleshooting, no-load operation wil 1 be minimized. If the troubleshooting operation extends over a period of time (that is, 3 to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or more), the engine shall be cleared in accordance with the manufacturer's recommendations for no-load and light-load operation.

On the basis of its review of the diesel generator testing no-load and light-load operation and procedures to be implemented by the applicant, the staff concluded in Section 9.6.3.1 of the SER that the applicant needed to define "extended period of time" of operation and when, during this time period of no-load and light-load operation, the diesel generator would be electrically loaded. The staff also required that Procedure (a), described in the appli-cant's letter dated March 25, 1982 and listed above, be modified as follows:

Whenever the diesel generator is started and its operation is not terminated within 2 minutes after startup, the diesel generator shall be loaded to at least 25% of full load for a minimum of 30 minutes; if the diesel generator is operated in a no-load or light-load mode for an extended period of time (not to exceed 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />), the generator shall be loaded to a minimum of 25% of full load for a minimum of 30 minutes, or as recommended by the manufacturer. Finally, that Procedure (a) as modified and Procedures (b) and (c) listed above are to

.be implemented by the applicant before plant startup.

In Section 8.3.1.1.3.2 of the FSAR, Amendment 8 (CEI letter dated March 25, 1982), the applicant documented his commitment to implement Procedure (a),

modified as required by the staff, and Procedures (b) and c) for diesel genera-tor no-load and light-load operation and defined "extended period of time" for such operation. This response is acceptable to the staff and satisfactorily resolves Confirmatory Issue (50), listed in Section 1.10 of the SER - this issue was initially listed as License Condition (8) in the SER, but was changed to Confirmatory Issue (50) in Supplement No. 1 to the SER.

Perry SSER 2 9-3

12 RADIATION PROTECTION 12.3 Radiation Protection Design Features 12.3.2 Shielding Section 12.3.2 of the SER contained a conditional acceptance of the shielding for the inclined fuel transfer system (IFTS), subject to (1) the applicant providing plant drawings of areas through which spent fuel bundles pass and (2) performance of a shielding design review demonstrating that radiation zones meet the staff positon stated in Section 12.3 of NUREG-0800. The necessary information was provided in Amendment 10 to the Perry FSAR and referenced in the applicant's letter (M. R. Edelman to B. J. Youngblood) dated December 21, 1982.

The result~ of the applicant's shielding design review of the IFTS demonstrate that accessible areas through which spent fuel bundles pass will either meet the maximum instar.taneous dose rate permitted in NUREG-0800 or will be con-trolled using an electronic key activation system. The electronic key system will not allow access to an area during spent fuel transfer.

The staff a,cordingly concludes that the Perry plant's shielding for the IFTS meets the criteria of NUREG-0800 and is therefore acceptable. This action re-solves Confirmatory Issue (44), listed in Section 1.10 of the SER.

12.3.4 Area Radiation and Airborne Radioactivity Monitoring Instrumentation 12.3.4.1 Area Radiation Monitoring Instrumentation In Section 12.3.4.1 of the SER:, the staff found the applicant's containment high-range gamma monitoring system acceptable. However, the staff required plant layout drawings identifying the location of the monitors to complete its evaluation and, therefore, considered this to be a confirmatory issue. In a letter dated October 14, 1982 (0. R. Davidson to A. Schwencer), the applicant provided specific information on the location of the four area radiation moni-tors instead of providing plant layout drawings. The staff finds that this additional information adequately addresses this issue in that the postaccident high-range monitors will be located in the plant in compliance with TMI Action Plan Item 11.F.l.3 requirements. Therefore, the staff concludes that Confirma-tory Issue (45), listed in Section 1.10 of the SER, has been satisfactorily addressed by the applicant and is considered to be resolved.

Perry SSER 2 12-1

13 CONDUCT Of OPERATIONS 13.2 Training Program 13.2.1 Licensed Operator Training Program 13.2.1.9 Operator Requalification Program In Section JJ.2.1.9 of the SER, the staff found as a confirmatory issue that the applicant's operator training program required further emphasis on teaching plant operators the use of equipment and systems to control or mitigate acci-dents in which the core is severely damaged to fully comply with the require-ments of THI Action Plan Item II.B.4. In a letter dated September 13 1 1982 (D. R. Davidson to A. Schwencer), the applicant furnished an outline of the program under development that the staff finds adequately addresses this con-firmatory issue. The applicant's response has also been found to be consistent with the criteria in Section 13.2.1 of the Standard Review Plan (NUREG-0800).

Thus, Confirmatory Issue (46), listed in Section 1.10 of the SER, is considered to be resolved.

13.2.2 Training for Nonlicensed Plant Staff 13.2.2.1 Conclusion In Section 13.2.2.1 of the SER, the staff reviewed the applicant's overall training program for nonlicensed plant staff and concluded that the training program met the requirements of American National Standards Institute (ANSI)

NlB.1-1971 as endorsed by Regulatory Guide 1.8, Revision 1, and 10 CFR 50, Appendix R, Section I, except that, as a confirmatory issue, the applicant was required to furnish additional informat on on the training program to be estab-lished for the Nuclear Project Training )ection (NPTS). In a letter dated September 13, 1982 (0. R. Davidson to A. Schwencer), the applicant provided additional information in response to this confirmatory issue.

On the basis of its review of the additional information provided by the appli-cant and a site visit made by the staff on November 2, 1982, which consisted of interviews with selected CEI project personnel, the staff found that the NPTS is developing procedures, programs, and recordkeeping activities to allow the Perry Plant Department Training Unit (PPDTU) to be absorbed into the NPTS at fuel load of Unit 1. The PPOTU is working with the NPTS in this development and in the consolidation of training of construction and operating engineering personnel. BWR systems training for construction and operating engineering personnel has been provided by the PPOTU. Similar training is planned for Nuclear Test Department personnel. Training of nonlicensed personnel is being removed from these departments and assigned to the PPOTU. The PPDTU is develop-ing qualification standards for all Perry plant department positions for which training is required. These standards will be based on job specification, guidelines of the Institute of Nuclear Power Operations (INPO), industry expe-rience, and departinent input. INPO generic task analysis will also be used in Perry SSER 2 13-1

this development effort. The present technical personnel staffing levels are 85 in the NPTS and 12 in the PPDTU with projections at Unit 1 fuel load of 15 for the NPTS and 17 for the PPDTU.

The staff concludes that the applicant's training program, when it is reorga-nized and the staff is complete, will meet the applicable requirements stated above and is consistent with the acceptance criteria of NUREG-0800, Sec-tion 13.2.2. Therefore, Confirmatory Issue (47), listed in Section 1.10 of the SER, is considered to be satisfactorily resolved.

13.5 Plant Procedures 13.5.1 Administrative Procedures 13.5.1.8 Shift Supervisor Responsibilities In its review of the applicant's administrative procedures, as reported in Section 13.5.1.8 of the SER, the staff found the duties, responsibilities, and authority of the Shift Supervisor and control room operators to be a confirma-tory issue and required the applicant to provide a written commitment to have the Shift Supervisor training program emphasize and reinforce the management functions and authority of the Shift Supervisor to ensure safe operation of the plant in conformance with the requirements of TMI Action Plan Item I.C.3.

In a letter dated September 13, 1982 (0. R. Davidson to A. Schwencer), the applicant provided the following written commitment in response to this confirmatory issue:

A corporate management directive will be issued establishing the command duties of the Shift Supervisor that emphasizes the primary management responsibility for safe operation of the plant. Plant administrative procedures will define the duties, responsibilities and authority of the Shift Supervisor and control room operators.

The Shift Supervisor training program will emphasize and reinforce the responsibility for safe operation of the plant and the Shift Supervisor's role in assuring plant safety.

The staff finds that this written commitment is acceptable in meeting the training requirements of TMI Action Plan Item I.C.3 and that it conforms with the criteria of NUREG-0800, Section 13.5.1. Thus, Confirmatory Issue (48),

listed in Section 1.10 of the SER, is resolved.

13.5.1.11 Verify Correct Performance of Operating Activities In SER Section 13.5.1.11, the staff evaluated the applicant's procedure for equipment control and surveillance audit activities to verify correct perform-ance of the plant operating activities for compliance with THI Action Plan Item I.C.6 requirements. The staff concluded this area to be a confirmatory issue subje~t to receipt of a description of the applicant's plans for verifying cor-rect implementation of equipment control measures in radiation areas. In a letter dated ~eptember 13, 1982 {D. R. Davidson to A. Schwencer), the applicant stated that procedures for verifying the functional acceptability of any equip-ment that is important to safety are under development and will be fully in Perry SSER 2 13-2

accordance with TMI Action Plan Item I.C.6. For equipment control measures in radiation areas, as low as is reasonably achievable considerations will be taken into account in the procedure development.

The staff considers this response acceptable and finds that the procedures to be developed will meet the requirements of TMI Action Plan Item I.C.6 and the criteria of NUREG-0800, Section 13.5.1. Therefore, Confirmatory Issue (49),

listed in Section 1.10 of the SER, is resolved.

Perry SSER 2 13-3

16 TECHNICAL SPECIFICATIONS On the basis of the staff's review of the Perry emergency core cooling system's functional design regarding the adoption by CEI of the Licensing Review Group-II position paper on the automatic depressurization system (ADS) design for Perry (discussed in Section 6.3.1.3 of this supplement), Item (7) is being added to those listed in Section 16 of the SER to require the applicant to perform a periodic surveillance of the low-pressure air alarm systems as an NRC Technical Specification. This surveillance requirement is being imposed to ensure that the Perry backup air system will provide continued long-term assurance of the availability of a sufficient inventory of air to actuat.e the ADS valves if they are needed. Specifically, at least once every 31 days, the applicant will be required to perform a channel functional test of the accumulator backup com-pressed air system low-pressure alarm systems, and at least every 18 months, the applicant will be required to perform a channel calibration of the accumu-lator backup compressed gas system low-pressure alarm systems and verify the air alarm setpoint of 2,000 +/- 75 psig on decreasing pressure.

A composite list of the items contained in Section 16 of the SER, including the item discussed above, follows (the SER section in which each item is dis-cussed is given in parentheses):

(1) Response-time testing {7.2.2.6)

(2) Systems shared by Units 1 and 2 (7.3.2.4)

(3) Single-loop operation subject to staff approval of supporting analysis (4.4.4)

(4) Operation in natural circulation made subject to completion of staff generic evaluation of thermal-hydraulic stability for BWRs (4.4.4)

(5) Core flow is to be checked by the applicant at least once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to account for possible buildup of crud deposition {4.4.5)

(6) Availability, setpoints, and frequency of surveillance requirements will be imposed for Level 8 trip and turbine bypass equipment to ensure an acceptable level of performance for anticipated operational transients (15.1)

(7) Periodic surveillance of the low-pressure air alarm systems to ensure that the backup air system will provide continued inventory of air to actuate the ADS valves if they are needed (6.3.1.3)

Perry SSER 2 16-1

18 CONTROL ROOM DESIGN REVIEW The staff reviewed the applicant's interim report describing the detailed con-trol room design review (DCROR) for Unit l, submitted by CE! letter dated June 7, 1982 (0. R. Davidson to A. Schwencer), and has performed an in-progress audit of the Unit 1 control room in August 1982. A report of the staff's audit find-ings were submitted to CEI in a letter dated November 12, 1982. Safety signifi-cant human engineering deficiencies (HEOs) identified by the applicant in the OCROR and those found during the staff's in-progress audit are to be corrected before Unit 1 is licensed. If a safety significant HEO cannot be corrected before licensing, the applicant will be required to provide a rationale for deferral, an interim prelicensing correction, and a reasonable schedule for implementing the longer-range correction. The staff will assess the extent to which HEOs, which are to be corrected subsequPnt to licensing, should be cited as a condition in the operating license issued, including a time when each particular HEO must be resolved during Unit 1 operation.

CEI has been asked to arrange a schedule for the staff's final audit, which is to address the closeout of TMI Action Plan Items I.0.1 and II.K.3.27. Until this final audit is satisfactorily completed, Outstanding Issue (7), listed in Section 1.9 of the SER, will continue to remain unresolved.

Perry SSER 2 18-1

APPENDIX A CONTINUATION OF CHRONOLOGY PERRY NUCLEAR POWER PLANT, UNITS 1 AND 2 NOTE: This appendix lists correspondence between NRC and the applicant inadver-tently omitted in the SER and Supplement No. 1, in addition to continuing the chronology, in this supplement.

March 13, 1981 letter from applicant submitting Amendment 1 to the FSAR.

May 22, 1981 Letter from applicant submitting Amendment 2 to the FSAR.

June 19, 1981 Letter from applicant transmitting Gilbert Associates report on control of heavy loads (NUREG-0612).

September 11, 1981 letter from applicant submitting Amendment 3 to the FSAR.

October 2, 1981 letter from applicant submitting Amendment 4 to the FSAR.

November 3, 1981 Letter from applicant submitting Amendment 5 to the FSAR.

November 3, 1981 NRC letter to applicant regarding NUREG-0737, Item II.K.3.44.

February 10, 1982 letter from applicant submitting Amendment 6 to the FSAR.

March 25, 1982 letter from applicant responding to SER Confirmatory Issue (50).

May 6, lQ~2 Letter from applicant responding to NRC staff concerns regarding fire protection issues.

May 20, 1982 Letter from applicant responding to draft SER structural engineering concerns.

May 27, 1982 letter from applicant submitting Amendment 7 to the FSAR.

June 2, 1982 Letter from applicant responding to questions concerning the structural design of the Perry intake and discharge water tunnels.

June 2, 1982 letter from applicant providing the plan for preoperational vibration monitorinJ program for balance-of-plant systems.

June 2, 1982 Letter from applicant documenting May 12, 1982 equipment qualification meeting.

June 7, 1982 Letter from applicant responding to req"est for additional information regarding containment buckling analyses.

Perry SSER 2 A-1

June 7, 1982 Letter from applicant providing the results of the detailed control room design review for Unit 1.

June 7, 1982 Letter from applicant responding to SER Confirmatory Issue {22).

June 8, 1982 Letter from applicant responding to SER Confirmatory Issues

{23) and {24).

June 9, 1982 NRC letter identifying concerns regarding the use of CO 2 in the control room.

June 9, 1982 Letter from applicant summarizing the reactor vessel struc-tural analysis for control of heavy loads.

June 14, 1982 NRC letter identifying Mark III containment design safety issues.

June 16, 1982 Letter from applicant responding to SER Outstanding Issue (15).

June 22, 1982 Letter from applicant describing design modifications for "fast scram" hydrodynamic loads on control rod drive (CRD) systems.

July 20, 1982 Letter from applicant regarding SER Outstanding Issue (12).

July 21, 1982 Letter from applicant requesting extension of Units 1 and 2 construction completion schedules.

July 28, 1982 NRC letter regarding unresolved fire protection safety issues in the SER.

July 30, 1982 NRC letter providing agenda for Unit 1 in-progress control room audit.

July 30. 1982 NRC letter providing the Advisory Committee on Reactor Safe-guards (ACRS) report on Unit 1.

August 5, 1982 Letter from applicant regarding Mark III co11tainment design safety issues.

August 5, 1982 Letter from applicant revisinq op~rating li~ense applica-tions to 40 years from date or i~sudnce of the licenses.

August 12, 1982 NRC letter regardiny qualification of safety-related equip-ment for hydrodynam1 c loads.

August 13, 1982 Letter from applicant summarizing standby liquid control and other design features for mitigation of anticipated transients without scram.

Perry SSER 2 A-2

August 16, 1982 Letter from applicant regarding feedwater check valve func-tion following a line break outside containment.

August 16, 1982 Letter fro* applicant providing containment annulus con-crete design, construction, and testing.

August 18, 1982 Letter from applicant providing additional information regarding "fast scram" hydrodynamic loads on CRD systems.

August 18, 1982 NRC letter issuing SER Supplement No. 1.

August 18, 1982 Letter from applicant regarding the environment~l qualifi-cation program.

August 20, 1982 Letter from applicant responding to SER Confirmatory Issue (15).

August 25, 1982 Letter from applicant submitting Amendment 8 to the FSAR.

August 26, 1982 Letter from applicant responding to SER Confirmatory Issue (34).

August 26, 1982 Letter from applicant responding to ACRS report on Unit 1.

August 30, 1982 NRC letter requesting additional information on the Emer-gency Plan.

August 30, 1982 Letter from applicant providing additional information concerning qualification of safety-related equipment to hydrodynamic loads.

August 31, 1982 Letter from applicant responding to SER Outstanding Issue (16).

August 31, 1982 letter from applicant responding to SER Confirmatory Issues (36), (37), (38), and (39).

September 1, 1982 Letter from applicant responding to SER Outstanding Issues (13) and (14).

September 2, 1982 Letter from applicant submitting the preservice inspection program plan.

September 8, 1982 NRC letter identifying SER Outstanding Issue (21).

SPptelllber 9, 1982 letter from applicant regarding SER Outstanding Issue (3).

Septelllher 9, 1982 Letter fro* applicant regarding SER Outstanding Issue (8).

Septellber 9, 1982 Letter frOII applicant documenting position on fuel issues -

SER Confiraatory Issues (11}, (12), (13), and (14).

Perry SSER 2 A-3

September 9, 1982 letter from applicant providing additional information on emergency planning.

September 13, 1982 Letter from applicant regarding SER Confirmatory Issues (46), (47), (48), and (49).

September 15, 1982 Letter from applicant responding to Idaho Nuclear Engineer-ing Laboratory draft technical evaluation report on control of heavy loads (NUREG-0612).

September 15, 1982 letter from applicant providing advance copies of FSAR Sections 3.10 and 3.11.

September 16, 1982 NRC letter requesting additional information regarding degraded core hydrogen control.

September 16, 1982 letter from applicant committing to several licensing Review Group-II generic issue positions.

September 17, 1982 letter from applicant providing additional information on seismic and dynamic qualification of mechanical and electrical equipment.

September 20, 1982 Letter from applicant providing Revision 2 to the Fire Protection Evaluation Report.

September 22, 1982 Letter from applicant providing the revised Perry corporate quality assurance (QA) program.

September 22, 1982 letter from applicant providing Revision O of the Emergency Plan.

September 22, 1982 Letter from applicant responding to SER Confirmatory Issue (16).

September 28, 1982 Letter from applicant responding to SER Outstanding Issue (21).

September 29, 1982 Letter from applicant providing additional information regarding degraded core hydrogen control.

September 30, 1982 Letter from applicant submitting Amendment 9 to the FSAR.

October 5, 1982 NRC letter clarifying request for additional information in the resolution of SER Outstanding Issue (2l).

October 8, 1982 letter from applicant providing reactor internals vibration prototype test program.

October 8, 1982 Letter from applicant providing Kuosheng safety/relief valve (SRV) test data.

October 14, 1982 Letter from applicant responding to SER Confirmatory Issues (28),(30), and (33).

October 14, 1982 Letter from applicant responding to SER Confirmatory Issues (32) and (45).

October 15, 1982 Letter from applicant providing additional information regarding SRV hydrodynamic loads.

October 19, 1982 NRC letter requesting clarification and additional information regarding QA lists documented in FSAR Amendments 8 and 9.

October 25, 1982 Letter from applicant responding to SER Confirmatory Issue (27).

November 3, 1982 NRC letter transmittng report of o~tober 6, 1982 emergency preparedness meeting.

November 4, 1982 NRC letter requesting additional information to resolve SER Outstanding Issue (12).

November 8, 1982 Letter from applicant amending September 15, 1982 letter regarding control of heavy loads (NUREG-0612).

November 8, 1982 Letter from applicant regarding containment annulus concrete design requirements.

November 12, 1982 NRC letter providing the staff's Unit 1 control room design interim audit report.

November 16, 1982 Letter from applicant providing additional information rega,'di ng SER Confirmatory Issue ( 36).

November 16, 1982 Letter from applicant regarding SER Outstanding Issue (21).

November 17, 1982 Letter from applicant providing additional information on SRV hydrodynamic loads.

November 23, 1982 Letter from applicant submitting Amendment 10 to the FSAR.

November 26, 1982 NRC letter on staff's findings regarding SER Outstanding Issues (15) and (16) and Confirmatory Issue (36).

November 30, 1982 NRC letter requesting automatic depressurization system modifications ce>ntmitment to THI Action Plan Item II.K.3.18 (SER Confirmatory Issue (25)).

November 30, 1982 NRC letter requesting information for equipment qualifica-tion Judit scheduling.

December 1, 1982 letter from applicant requesting extension of construction permit completion dates for Units 1 and 2.

December 2, 1982 letter from applicant responding to SER Confinnatory Issue (20) and Outstanding Issue {10).

December 21 1982 letter from applicant identifying management changes effective December I, 1982.

December 14, 1982 NRC letter requesting additional information regarding SRV piping and quencher device.

December 21, 1982 letter from applicant regarding SER Outstanding Issue (21).

December 21, 1982 letter from applicant responding to SER Confirmatory Issues (41) and (42).

December 21, 1982 letter from applicant regarding SER Confirmatory Issue (44).

December 21, 1982 Letter from applicant responding to QA question posed in NRC letter dated October 19, 1982.

December 23, 1982 NRC letter regarding proposed changes to the Perry Environmental Monitoring Program.

December 27, 1982 NRC letter transmitting draft Standard Technical Specification for BWR/6 plants.

December 29, 1982 NRC Order extending construction completion dates for Perry, Units 1 and 2.

APPENDIX B REFERENCES*

American Industrial Hygienists Association, Hygienic ~uide, 1964.

Bush, S. H., 11 Probability of Damage to Nuclear Components, 11 Nuclear Safety, 14(3):187, May-June 1973.

---, "A Reassessment of Turbine-Generator Failure Piobability, 11 Nuclear Safety, 19(6):681, Nov.-Dec. 1978.

Cleveland Electric Illuminating Company, "Perry Nuclear Power Plant, U:;it Nos. 1 and 2, Final Safety Analysis Report," Docket Nos. 50-440/441, Jan. 30, 1981 Code of Federal ReQulations, Title 10 (10 CFR), "Energy" (includes General Design Criteria).

General Electric Topical Report NEDE-22203-P, "Reactor Internals Vibration Predictions," Aug. 1982. (Proprietary. Not publicly available.)

---, NEDO 10466, "Power Generation Control Complex Design Criteria and Safety Evaluation," Rev. 2, Mar. 1978.

Letter, Aug. 9, 1976 from G. G. Sherwood (General Electric) to B. C. Rusche (NRC),

Subject:

Selection of BWR/6 Relief Valve Control System Modifications.

Dec. 22, 1980 from 0. G. Eisenhut (NRC) to operating license holders,

Subject:

Submission of NUREG-0612.

May 17, 1982 from D. L. Holtzscher (Illinois Power Company) to H. J.

Faulkner (NRC),

Subject:

Submittal of Position P3pers for Licensing Review Group-II Issues.

Memorandum, Aug. 19, 1982 from L. S. Rubenstein to T. M. Novak,

Subject:

Resolution of LRG-II Channel Box Deflection Issue (LRG-II Issue 3-CPB).

National Institute of Occupational Safety and Health, "Occupation Health Guide for Carbon Dioxide,' 1 Publication 81-i23, Washington, DC, 1981.

U.S. Nuclear Regulatory Commission, NUREG-0612, 11 Control of Heavy Loads at Nuclear Power Plants - Resolution of Generic Technical Activity A-36,"

July 1980.

• All correspondence between the applicant and the NRC referencea in this supplement is listed ir, Appendix A of this supplement.

Perry SSER 2 B-1

' .)/J,.,4,,,,,J.J&i.). ,j C'! JL ,J.,J,L, J., . ,. JJL, .J,.JL LL ., .. H '**" JJ . L . kB.£.. . !,ti ...,. 2,3111!1-Li., .*. J .. ," ,... ,.I.IL, .,L )I. t I J.JU: ,,,J likl.S J.p!JJi.ji 11 NUREG-0737, Clarification of TMI Action Plan Requirements," Nov. 1980.

NUREG-0800 (formerly NUREG-75/087), "Standard Review Plan for Review of Safety Analysis Reports for Nuclear Power Plants," July 1981 (includes Branch Technical Positions}.

NUREG-0887, "Safety Evaluation Report Related to the Operation of Perry Nuclear Power Plant, Units 1 and 2," May 1982 and Supplement No. 1, Aug. 1982.

Regulatory Guide 1.8, 11 Personnel Selection and Training," Rev. l, May 1977.

Regulatory Guide 1. 11, 11 Instrument Lines Penetrating Primary Reactor Con ta i nnient," Feb. 1982.

Regulatory Guide 1.20, "Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing,"

Rev. 2, May 1976.

Regulatory Guide 1.115, "Protection Against Low-Trajectory Turbine Missiles,° July 1977.

Regulatory Guide 1.117, "Tornado Design Classification," June 1976.

U.S. Nuclear Regulatory Co:*1mission, Office of Inspection and Enforcement, Bul-letin 79-02, "Pipes Support Base Plate Designs Using Concrete Expansion Anchor Bolts." Mar. 2, 1979.

Bulletin 79-27, 11 Loss of Non-Class-IE Instrumentation and Control Power System Bus During Operation," Nov. 30, 1979.

Bulletin 80-06, 11 tngineered Safety Feature (ESF} Reset Controls," Mar. 13, 1980.

Industry Codes and Standards American Institute of Steel Construction (AISC), "Specification for Design, Fabrication and Erection of Structural Steel for Buildings," Sixth Edition, New York, N.Y., 1969.

American National Standards Institute (ANSI), NlB.1**1971, "SelP-.:tion and Train-ing of Nuclear Power Plant Personnel,° 18.1-1978 (p. 13-14).

American Society for Testing and Materials (ASTM}, E-185-73," Standard Recom-mended Practices for Surveillance Tests for Nuclear Reactor Vessels."

American Society of Mechanical Engineers (ASHE}, "Boiler and Pressure Vessel Code,"Section III, "Nt.clear Power Plant Components," Appendix G, "Pro-tection Against Non-Ductile Failure."

Section III, Subsection NF.

Perry SSER 2 B-2

---,Section XI, "Rules for Inservice Inspection of Nuclear Reactor Coolant Systems."

Institute of Electrical and Electronics Engineers, Standard 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations. 11 Perry SSER 2 8-3

APPENDIX C UNRESOLVED SAFETY ISSUES C.5 Discussion of New USis as Th~., Relate to Perry Unit$ land 2 Task A-11 Reactor Vessel Materials Toughness In Section C.5, Appendix C1 of the SER, the staff identified, as an unresolved safety issue (USI), reactor vessel materials toughness. On the basis of its evaluation of the Perry reactor vessel materials, the staff concluded that Perry could operate before resolution of this generic issue without undue risk to the health and safety of the public. Since issuance of the SER and Supple*

ment No. 1 to the SER, the staff has completed its generic assessment of this USI. The results of this effort have been documented in NUREG-0744, 11 Resolution of the Task A-11 Reactor Vessel Materials Toughness Safety Issue," Volumes I and II, Revision l, published in October 1982.

NUREG-0744 provides the staff's position with respect to the reactor vessel s~fety analy~is acco~ding to the rules ~iven in the ~ode qf FetJ9ral ~eautatiQn$.

Title 10, which requires that an analys1s be performed whenever neutron frradfa-tion reduces the Charpy V-notch upper-she.If energy level in the vessel steel to 50 ft-lb or less. Task A-11 was undertaken because the available enqineering methodology for such an analysis used linear elastic fracture mechan1cs prin*

ciples, which could not fully account for the plastic deformation or stable crack extension expected at upper-shelf temperatures. The goal of Task A-11 was to develop an elastic-plastic fracture mechanics methodology applicable to the beltline region of a pressurized-water-reactor vessel that could be used in the required safety analysis. This goal was achieved with the help of a team of recognized experts.

Therefore, NUREG-0744, Revision 1, completes the staff's resolution of USI A*ll.

The information contained therein will be the basis for licensing actions taken by the NRC relative to the toughness requirements set fortr in 10 CFR 50, Appen-dix G. NRC generic letter :No. 82-26), dated November 12, 1982. encourages CEI to review NUREG-0744, Revision l, and consider its application in those cases where it may be necessary to submit a fracture analysis for staff review and approva 1.

C.6 References Code of Federal Regulations, Title 10 (10 CFR), "Energy."

Letter, Nov. 12, 1982, from 0. G. Eisenhut (NRC} to all power reactor licensees,

Subject:

NUREG*0744, Rev. l .. Pressure Vessel Material Fracture Toughness (Generic Letter 82-26).

Perry SSER 2 C-1

U.S. Nuclear Regulatory Commission, NUREG-0744, "Resolution of the Task A-11 Reactor Vessel Materials Toughness Safety htut," Vols. land ll, Rev. 1, Oct. 1982.

Perry SSIR 2

APPENDIX E NRC STAFF CONTRIBUTORS ANO CONSULTANTS This supplement to the Safety Evaluation Report is a product of the NRC staff. NRC staff members listed below were principal contributors to this supp 1ement.

Name Title Branch B. E11 iot Materials Engineer Materials Engineering N. Fioravante Auxiliary Systems Engineer Auxiliary Systems R. Giardina Reactor Systems Engineer Power Systems (Mechanical)

T. Greene Systems Engineer Containment Systems M. Haughey Mechanical Engineer Equipment Qualifications M. Lamastra Senior Radiation Engineer Radiological Assessment J. Mauck Reactor Engineer (Instrumentation) Instrumentation and Control E. Pedersen Nuclear Engineer (Management Licensing Qualifications Systems)

J. Peschel Reactor Inspector Region III Management Programs Sect ion J. Read Nuclear Engineer - Chemist Accident Evaluation S. Rhow Reactor Systems Engineer Power Systems (Electrical)

0. Serig Human Factors Engineer Human Factors Engineering

0. Shum Systems Engineer Licensing Qualifications J. Stang Fire Protection Engineer Chemical Engineering f-M Su Syste~s Engineer Generic Issues

0. Terao Mechanical Engineer Mechanical Engineering S*L Wu Reactor Fuels Engineer Core Performance Perry SSER 2

APPENDIX G ERRATA TO THE SAFETY EVALUATION REPORT Pa,ge Section/Table Change 1-11 1.11 For Item (4) delete asterisks.

1-13/1-14 Table 1.1 Under column, "SER Section, 11 for "Issue 4-RSB, 11 add "6.3.1.3";

"Issue 6-RSB, 11 change 11 5.4.7 11 to "5.4.2 11 ;

11 Issue 1-CPB," change 11 4.2.3.2 11 to 11 4.2.3.3 11 ;

"Issue 2-CPB," change 11 4.2.1.3 11 to 11 4.2.3.2 11 and "4.2.4.3" to u4.2.3.3 11 ;

11 Issue 2-CSB, 11 change 11 6.2.5 11 to 11 6.2.7 11 ;

"Issue 4-ASB, 11 change 11 9.4.5.4 11 to 11 9.4.5.3. 11 Under column, "Title {TMI Action Plan Item)" for "Issue 8-RSB, 11 add "(II. K. 3. 28) 11 at end of the title.

1-17 Table 1. 2 Add new item, "II.K.3.28; Qualification of ADS Accumulators; 6. 3. 1. 311 under the respective columns.

3-37 3.9.3.1 At the end of the last sentence of paragraph 4, add the f o11 owing: "when the app 1 i cant responds to Outstanding Issue {6) - see Section 6.2.1.8 of this report".

5-30 5.4.2 In the third full paragraph, last line, change 11 6.3.2.3 11 to 11 6.3.1.3 11

• 6-17 6.2.7{3) In Item {f), change "6.2.4" to "3.9.3.2.l", and at the end of the sentence add "which will be addressed separately in the resolution of Confirmatory Issue (7)."

6. 3.1. 3 In third full paragraph, last line, after "check valves," add 11 to meet the requirements of TMI Action Plan Item II.K.3.28 {also LRG-II Generic Issue 8-RSB)".

6-24 6.3.1.3 In paragraph 4, 1ine 5, change 11 8-RSB" to 11 4-RSB".

Perry SSER 2 G-1

NRC nn, FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1.N1f,ff P,! 08~'3E A fAuiyned bv DDCJ BIBLIOGRAPHIC DATA SHEET Supplement No. 2 4 TJTLE AND SUBTITLE (AddVal11meNo.,dapproq11dtf!J 2. (Le1We blank}

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I AUTHOAiSl 5. DA TE REPORT COMPLE T(;O MONl'H I YEAH 9 PERfOfll\HN<j OflGANIZA TION NAME ANO MAILING ADDRESS (Include Z,p Code) DATE REPORT ISSUED U. S. Nuclear Regulatory Cammi ssion MONTH I YEAR Office of Nuclear Reactor Regulation Washington, D. C. 20555 - 6 {LeJv,* bfar1A I

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15 SUl'PLEMfN fARY NOTES I 4 (Le,1v1! /Jl,mA I Pertains to !he ket Nos. 50-44 0 and 50-441 16 ABSTHACT (200 words or 11ml Supplement No 2 to the Safety Evaluation Report on the application filed by the Cleveland Electric Il 1uminati ng Company on beha 1 f of f tsel f and as agent for the Duquesne Light Company, the Ohio Edison Company, the Pennsylvania Power Company and the Toledo Edison Company (the Central Area Power Coordination Group, CAPCO),

as applicants and owners, for a license to operate the Perry Nuclear Power Plant, Units 1 and 2 {Docket Nos. 50-440 and 50-441). The facility is located near lake Erie in Lake County, nhio. This supplement has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission and reports the status of certain items that had not been resolved at the time of publication of the Safety Eva 1ua t ion Report.

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