ML17139C297

Safety Evaluation Report Related to the Operation of Susquehanna Steam Electric Station,Units 1 and 2.Docket Nos. 50-387 and 50-388.(Pennsylvania Power and Light Company; Allegheny Electric Cooperative,Incorporated)

ML17139C297
Person / Time
Site:	Susquehanna
Issue date:	03/31/1984
From:	Office of Nuclear Reactor Regulation
To:
References
NUREG-0776, NUREG-0776-S06, NUREG-776, NUREG-776-S6, NUDOCS 8404110036
Download: ML17139C297 (100)

Text

NU BEG-0776 Supplement No. 6 Safety Evaluation Report related to the operation of Susquehanna Steam Electric Station, Units 1 and 2 Docket Nos. 50-387 and 50-388 Pennsylvania Power & Light Company Allegheny Electric Cooperative, Inc.

U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation March 1984

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ABSTRACT In April 1981, the staff of the Nuclear Regulatory Commission issued its Safety Evaluation Report (NUREG-0776) regarding the application of the Pennsylvania Power 4 Light Company (the applicant and/or licensee) and the Allegheny Elec-tric Cooperative, Inc. (co-applicant) for licenses to operate the Susquehanna Steam Electric Station, Units 1 and 2, located on a site in Luzerne County, Pennsylvania.

Supplement 1 to NUREG-0776 was issued in June 1981 and addressed several out-standing issues.

Supplement 2 was issued in September 1981 and addressed addi-tional outstanding issues.

Supplement 2 also contains NRC staff responses to the comments made by the Advisory Committee on Reactor Safeguards in its report dated August ll, 1981.

Supplement 3 was issued in July 1982 and addressed five items that remained open and closed them out.

On July 17, 1982, Operating License NPF-14 was issued to allow Unit 1 operation at power levels not to ex-ceed 5X of rated power.

Supplement 4 was issued in November 1982 and discusses the resolution of several license conditions.

On November 12, 1982, Operating License NPF-14 was amended to remove the 5X power restriction, thereby permit-ting full-power operation of Unit 1.

Supplement 5 was issued in March 1983 and addressed several issues that required'esolution before licensing operation of Unit 2.

This supplement to NUREG-0776 addresses the remaining issues that required re-solution before licensing operation of Unit 2 and closes them out.

Susquehanna SSER 6

ABSTRACT TABLE OF CONTENTS Pacae 1

INTRODUCTION AND GENERAL DISCUSSION.

1. 1 Introduction.

1.9 Outstanding Issues 1.10 License Conditions 2

SITE CHARACTERISTICS

2. 2 Nearby Industrial, Transportation, and Military Facilities..

2. 2. 2 Nearby Facilities

2. 4 Hydrol ogy 2.4.4 Ultimate Heat Sink.

3 DESIGN CRITERIA FOR STRUCTURES,

SYSTEMS, AND COMPONENTS..........

3.10 Seismic and Dynamic qualification of Seismic Category I Mechanical and Electrical Equipment...

~.....

3.10.1 Balance-of-Plant Different Equipment.

3.10.2 Nuclear Steam Supply System Equipment............

3. 10.3 Fatigue Cycling Effects Due to Safety/

Relief Valve (SRV) Loading.

3.10.4 Summary..

3. 11 Environmental qualification.

3. 11. 1 Environmental qualification of Safety-Related Electrical Equipment 3.11.2 Background.

3.11.3 Staff Evaluation...........

4 REACTOR.

4.4 Thermal and Hydraulic Design.

4.6 Safety Concerns Associated With Scram Discharge System l-l 1-2 1-3 2-1 2-1 2-1 2-1 2-1 3-1 3-1 3"1 3-3 3-6 3-6 3-7 3-7 3-7 3-8 4-1 4-1 4-1 Susquehanna SSER 6

TABLE OF CONTENTS (Continued) 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.2 Integrity of the Reactor Coolant Pressure Boundary..........

5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing.

5.3 Reactor Vessel.

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5-1 5-1 5-1 5-2 5.3.1 5.3.2 5.3.3 Reactor Vessel Materials..

Pressure-Temperature Limits......

Reactor Vessel Integrity.......

5-2 5-5 5-6 6

ENGINEERED SAFETY FEATURES.

6.2 Containment Systems 6.2.1 Containment Functional Design.

6. 2.4 Containment Isolation Systems 6.6 Inservice Inspection of Class 2 and 3 Components............

6.6.3 Evaluation of Compliance With 10 CFR 50.55a(g) for Unit 2 7

INSTRUMENTATION AND CONTROL

7. 5 Safety-Related Display Instrumentation.

6-1 6-1 6-3 7-1 7-1 7.5.2 Specific Findings 7.5.3 Summary

'8 ELECTRIC POWER SYSTEMS 8.2 Offsite Power Systems 8.3 Onsite Emergency Power Systems AUXILIARYSYSTEMS..........

9.1 Fuel Storage and Handling.....

9.1.4 Fuel Handling System.

9.2 Water Systems....

9.2. 1 Emergency Service Water System.

9.2.3 Ultimate Heat Sink

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7-1 7-1 8-1 8"1 8-1 9-1 9-1 9-1 9-1 9-3 Susquehanna SSER 6

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TABLE OF CONTENTS (Continued) 9.5 Fire Protection Systems

9. 5. 5 Alternate Shutdown Systems 9.5.8 Appendix R Statement.

13 CONDUCT OF OPERATIONS 13.6 Industrial Security.

13. 6. 1 Introduction..

13. 6. 2 Physical Security Or ganization.

13. 6. 3 Physical Barriers..

13.6.4 Identification of Vital Areas..

13.6.5 Access Requirements.

13.6.6 Detection Aids 13.6.7 Communications 13.6.8 Test and Maintenance Requirements.

13.6. 9

Response

Requirements 13.6. 10 Employee Screening Program.

14 INITIALTEST PROGRAM..

17 QUALITY ASSURANCE 17.6 Confirmatory In-Depth Review Program.

22 TMI-2 REQUIREMENTS 22.2 TMI Action Plan Requirements for Applicants for Operating Licenses I

Operational Safety.

II Siting and Design.

APPENDICES A

CONTINUATION OF CHRONOLOGY OF NRC STAFF RADIOLOGICAL REVIEW OF SUSQUEHANNA STEAM ELECTRIC STATION, UNITS 1 and 2

B BIBLIOGRAPHY H

REVIEW'OF THE PRESERVICE INSPECTION PROGRAM FOR SUSQUEHANNA UNIT 2

~Pa e

9-3 9-3 9-4 13-1 13-1 13-1 13-1 13-1 13-2 13-2 13-3 13-3 13-3 13-4 13-4 14-1 17-1 17-1 22-1 22-1 22-1 22-2 Susquehanna SSER 6

vi 1

1 INTRODUCTION AND GENERAL 'DISCUSSION

1. 1 Introduction In April 1981, the staff of the Nuclear Regulatory Commission (NRC) (the staff) issued its Safety Evaluation Report (SER)

(NUREG-0776) regarding the application of the Pennsylvania Power & Light Company (PP8 L) (the applicant and/or licensee) and the Allegheny Electric Cooperative, Inc. (the co-applicant) for licenses to operate Susquehanna Steam Electric Station, Units 1 and 2.

In June 1981, the staff issued Supplement 1 to NUREG-0776, which documented the resolution of several outstanding issues in further support of the licensing activities.

In September 1981, the staff issued Supplement 2 to NUREG-0776, which addressed the open items identified in the SER and Supplement 1.

In July 1982, the staff issued Supplement 3 to NUREG-0776, which addressed all remaining open issues from previous supplements and closed them out.

On July 17, 1982, Operating License NPF-14 was issued for Unit l.

Operation was restricted to fuel loading and low-power testing at levels not to exceed 5X rated power.

In November 1982, the staff issued Supplement 4 to NUREG-0776, which addressed the resolution of several Unit 1 license conditions that had been met.

On November 12, 1982, Amendment 5 to Operating License NPF-14 was issued removing the 5X power re-striction, thus allowing Unit 1 operation at power levels not to exceed 100X rated power.

In March 1983, the staff issued Supplement 5 to NUREG-0776, which addressed several issues that require resolution before Unit 2 can be licensed for operation.

Each section containing issues addressed in this report, Supplement 6 to NUREG-0776, is numbered and titled to correspond to the sections of NUREG-0776 and its earlier supplements where they were previously discussed.

This report addresses the remaining issues that require resolution before Unit 2 can be licensed for operation and closes them out.

Copies of this report are available for public inspection at the Commission's Public Document

Room, 1717 H Street, NW, Washington, DC, and at the Osterhout Free Library, 71 South Franklin Street, Wilkes Barre, PA 18701.

Copies of this report also are available for purchase from the sources indicated on the inside front cover.

The NRC project manager for Susquehanna is Mr. Robert L. Perch.

Mr. Perch may be contacted by writing to the Division of Licensing, U.S.

Nuclear Regulatory Commission, Washington, DC 20555.

The following additional NRC staff members contributed to this report, which is a product of the staff.

Name Tim Collins Randall Eberly Position Nuclear Engineer Fire Protection Engineer Susquehanna SSER 6

Barry El 1iot

'aterials Engineer Branch Reactor Systems Chemical Engineering Materials Engineering

Name Farouk Eltawila Position Senior Containment Systems Engineer Branch Containment Systems Mike Fleigel Section Leader Environmental and Hydrological Engineering Richard Froelich Senior Human Factors Engineer Human Factors Engineering Hukam Garg Martin Hum Arnold Lee Milliam Lefave Senior Electrical Engineer Senior Materials Engineer Senior Mechanical Engineer Mechanical Engineer Equipment equal ification Materials Engineering Equipment qualification Auxiliary Systems William Long Jerry Mauck Reactor Engineer Instrumentation and Control Systems Operational Safety Engineer Procedures and Systems Review Eugene McPeek Project Manager Standardization and Special projects Robert Wright'echanical Engineer 1.9 Outstandin Issues Sang Rhow Electrical Engineer Anton Sinisgalli Site Analyst Power Systems Site Analysis Equipment qualification In Section 1.9 of Supplement 5 to NUREG-0776, the'taff summarized the status of the identified remaining open items specifically for Unit 2.

In this report, the staff discusses the resolution of all of these items previously identified as

open, as well as additional information related to other sections of the SER.

The current status and sections in which the items are shown below.

Item Status Section staff evaluates the nine remaining (110) Ultimate heat sink performance test for two-unit operation Resolved 2.4.4, 9.2.3 (ill) Preservice inspection program Resolved (112) Review of 10 CFR Appendices G and H

Resolved

5. 2.4, 6.6 5.3.1 (113)

TMI Action Plan items License condition 22 Susquehanna SSER 6

1-2

Item (114) Control of heavy loads Status Section

'icense condition

9. 1.4 (115)

Response

to IE Bulletin 79-27 Resolved 7.5.2 (116) Environmental qualification of'lectrical equipment f

(117) Seismic qualification Review Team (SgRT)

License condition

3. 11 License condition

3. 10 (118)

AC electrical distribution system 1

1.10 License Conditions Resolved 8.0 There were several issues for which a condition was included in Operating License NPF-14 for Unit 1 to ensure that NRC requirements would be met during plant operation.

The staff considers that the issues listed below also require license conditions for Unit 2 unless satisfactory resolution is reached on these issues before licensing.

The current status and sections in which the staff evaluates these issues are shown below.

Issue (1)

Thermal and hydraulic design (2) qualification of purge valves (3)

Operation with partial feedwater heating at end of cycle Status Confirmatory Resolved License condition Section 4.4 22(II. E. 4. 2)

(4)

Inservice inspection program (5)

Nearby facilities (6)

Scram discharge system piping License condition Resolved Confirmatory 2.2.2 4.6 (7)

Environmental qualification License condition

3. 11 (8)

Assurance of proper design and construction Resolved

17. 6 (9)

Seismic and dynamic qualifications (10) Containment purge system (ll) Additional instrumentation and control concerns Resolved License condition 6.2.4 License condition 3.10 (12) Surveillance of control blade License condition Susquehanna SSER 6

1-3

Issue (13) Emergency diesel engine starting systems (14) Nuclear steam supply system - vendor review of procedures Status License condition License condition Section (15) Postaccident sampling (16) Instrumentation for detection of inadequate core cooling (17) Modification of automatic depressurization system logic License condition License condition 22(II. F. 2)

License condition 22(II.K.3.18)

(18) Effect of loss of power on alternating current pump seals Resolved 22(II. K. 3. 25)

(19) Upgrade emergency support facilities (20) Safety relief valve inplant test (21) Control room design review (22) Emergency service water system License condition Confirmatory 6.2. 1.8 License condition 22(I. D. 1)

License condition 9.2. 1 Susquehanna SSER 6

1-4

SITE CHARACTERISTICS 2.2 Nearb Industrial Trans oration and Militar Facilities 2.2.2 Nearby Facilities In Section

1. 10 of Supplement 5 to the SER, the staff provided a list of issues for which a condition was included in the operating license for Susquehanna Unit 1 for which a similar license condition would be required for Unit 2 unless satisfactory resolut;ion was reached on the issue before the licensing of Unit 2.

One such issue regarded the gas pipeline system near the Susquehanna site.

On February 25, 1983, PP&L submitted their response to License Condition 2.C(13) of the operating license for Susquehanna Unit 1.

This response described per-manent modifications to the 12-in.

gas pipeline system that limits the flow to 39 m~/sec near Susquehanna Steam Electric Station.

The staff reviewed the February 25, 1983, submittal and found it to be an acceptable approach in a letter to PP&L dated May 10, 1983.

In a letter dated November ll, 1983, PP&L stated that installation of the per-manent modifications that limit flow in the 12-in.

gas pipeline to 39 m~/sec had been completed.

This completes all the requirements under License Condi-tion 2.C(13) of the operating license for Susquehanna Unit l.

The staff con-siders this issue resolved for Susquehanna Unit 2.

2. 4

~Hdr~ol o g 2.4.4 Ultimate Heat Sink The SER stated that both the applicant's and staff's analysis of the spray pond's thermal performance indicated that it would be capable of providing cooling water below the design temperature of 95'F under the conditions speci-fied in Regulatory Guide 1.27, "Ultimate Heat Sink for Nuclear Power Plants."

The staff required, however, that the ability of the as-built spray pond to meet the thermal design basis be confirmed by actual performance tests.

The staff stated that staff review and approval of the performance test results and analysis would be required before fuel loading for Unit 2.

A description of the test plans and procedures and analysis techniques were to be submitted for staff approval before Unit 1 operation.

The performance test plans were submitted to NRC on June 16, 1982.

The staff approved those plans on July 22, 1982.

The performance tests were conducted from July 23 to July 25, 1983.

On December 21, 1983, the applicant submitted a final report to NRC on the results of the tests.

The applicant's report states that the measured spray pond performance was equal or superior to the applicant's model's predictions during periods of wind speeds at or below 4.5 mph.

The applicant's analysis of the tests for win'd speeds above 4.5 mph could not demonstrate conservatism of the applicant's analytic model.

The applicant has therefore reanalyzed the thermal performance of the Susquehanna SSER 6

2"1

spray pond using his analytic model but ignoring the effects of wind;; that is, the applicant assumed no wind for the entire 30-day period of severe meteorology used in the analysis.

This assumption is clearly conservative because the actual meteorological data

used, in conformance with Regulatory Guide 1.27, contain wind speeds ranging up to almost 12 mph.

Winds increase the efficiency of the heat transfer process even if the formulation used in the applicant's model was optimistic.

Thus, ignoring completely the wind s contribution to heat transfer is conservative.

The applicant's reanalysis of the pond's thermal performance, with winds

ignored, assumed a starting pond temperature of 81'F and an initial water inventory of 23 million gallons.

The maximum pond temperature calculated was 95.26 F.

The applicant has.requested a modification to the Technical Specifi-cations to require that pond temperature and inventory be within those limits during operation.

The applicant recognizes that the temperature limit of 81~F could be exceeded during the summer and is investigating changes that would allow an increase in this temperature limitation.

Although the staff has not performed an independent thermal analysis subsequent to the one discussed in the SER, it can conclude that, subject to the Technical Specification discussed

above, the spray pond is capable of providing cooling water below the design temperature.

This conclusion is based on the following factors.

The staff's computer evaluation of the spray pond performance cited in the SER used an initial pond temperature of 90.2 F.

Results of that analysis indicated a maximum pond temperature below the design level of 95~F.

Limiting the initial pond temperature to 81 F (by a Technical Specification) would, therefore, reduce the staff's calculated maximum pond temperature.

The applicant's revised analysis completely ignored the effects of wind speed, which is a substantial conservatism, and still showed generally satisfactory performance.

The staff, therefore, concludes that, subject to the Technical Specification discussed

above, the ultimate heat sink s thermal performance complies with Regulatory Guide 1.27 and thus meets the requirements of GDC 44.

Susquehanna SSER 6

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3 DESIGN CRITERIA FOR STRUCTURES,

SYSTEMS, AND COMPONENTS 3.10 Seismic and D namic uglification of Seismic Cate or I Mechanical and Electrical E ui ment The staff has reviewed the applicant's submittal of December 17, 1983, regarding the review of seismic qualification of equipment in Susquehanna Unit 2 and has determined that a plant site audit for Unit 2 is not necessary for the following reasons:

(1)

A successful Seismic Qualification Review Team (SQRT) audit was conducted on Unit 1 equipment.

(2)

There are very few differences between Unit 1 and Unit 2 equipment, its installation, or the environment in which it operates.

For example, a

review of balance-of-plant (BOP)

SQRT items has shown over 300 items that are similar in Units 1 and 2 and only 13 different items installed in Unit 2.

For dynamic qualification, Unit 2 is different from Unit 1 if equipment is unique or modified from the Unit 1 equipment, or if it is the same type but is placed in a different location or orientation in Unit 2 so that new analysis or testing is required.

(3)

In most cases the Unit 2 SQRT documentation has been satisfactorily ac-complished by referencing the Unit 1 report and analysis, by completing SQRT forms, and by listing the Unit 2 plant identification numbers to which the documentation applies.

'I (4)

For the Unit 2 equipment that differs from that in Unit 1, the SQRT documentation is done in the same manner and to the same criteria as the Unit 1 documentation.

The staff also has reviewed Revision 4 of the Susquehanna Equipment Qualifica-tion Summary Report dated September 9, 1983, as well as the applicant's letters of February 16,

1983, June 9, 1983, December 13, 1983, January 10, 1984, and February 1, 1984.

Of the equipment items different for Unit 2 that have been identified for both nuclear steam supply system (NSSS) and BOP scope, most have already been qualified or will have been qualified by fuel load with the excep-tion of those for which the justification of interim operation has been provided by the applicant.

The system arguments for the justification have been reviewed by the staff and were found acceptable.

To complete the Unit 2 review, the quali-fication status of Unit 1 common equipment

items, as well as the evaluation of NSSS equipment fatigue effects resulting from safety/relief valve (SRV) loadings, which are included in the Unit 1 license conditions, is also presented below.

3. 10.1 Balance-of-Plant Different Equipment

3. 10. 1. 1 Existing Equipment The following is a list of existing BOP equipment in Unit 2 that is different from equipment in Unit 1:

Susquehanna SSER 6

3-1

Control Rod Drive Platform - The Unit 2 control rod drive platform differs from the Unit 1 platform because of the new as-built conditions of the Unit 2 piping supports that are 'attached to the platform.

A new analysis using a conservative required response spectrum (RRS), which exceeded the Unit 1 and Unit 2 floor envelope spectra, has been conducted to qualify the equipment.

This is acceptable to the staff.

(2)

(3)

Reactor Top Head Insulation Frame - This item differs from the Unit 1 frame because of the many new connections added to support the piping containing Regulatory Guide 1.97 equipment.

A new analysis has been completed to account for the dynamic loading on the frame resulting from this new piping and equipment and the different routing of the Unit 2 piping system.

This is acceptable to the staff.

Motor Generator Set (E151) - This equipment is located in the center of a floor area in Unit 2, whereas the Unit 1 counterpart is located near the walls.

To account for the floor amplification effect, the equipment was finally qualified by showing that the respective Unit 2 nodal point required spectra were less than the test response spectra of the quali-fication testing.

The staff finds this to be acceptable.

Automatic Transfer Switch Unit (E152) - Same status and conclusion as those for the motor generator set (E151) apply.

(5)

Cooling Unit for Emergency Switchgear Room This is equipment unique to Unit 2 and has been completely qualified with completion of documentation.

(6)

Reactor Building Crane - The dissimilarity between Unit 1 and Unit 2 cranes is that the crane girders supporting the trolley of the smaller Unit 2 crane are separated by 16 ft instead of 22 ft as for the Unit 1 crane.

This produces a lighter trolley, but the crane weight is reduced by less than lOX.

In the analysis for the Unit 2 crane, the effect of'he above difference in configuration was accounted for, and the result was acceptable as shown in the S(RT documentation.

(7) 1500-lb Motor-Operated Gate Valves - The valves are installed in Unit 2 only and are qualified for seismic and hydrodynamic loads to a level of 10 g.

This qualification g level has been verified to exceed that which the valves experience at their respective locations in the Unit 2 piping systems and is acceptable to the staff.

Vacuum Relief Valves qualification of the new model Anderson-Greenwood vacuum relief valves for Unit 2 has been completed.

Installation of this design in Unit 2 will be completed before Unit 2 fuel loading.

Although the Unit 1 vacuum relief valves are dynamically qualified, this design is also scheduled for installation in Unit 1 during the Unit 1 first refueling outage.

(9)

Additional Gear-Operated Butterfly Valves - These valves were added to the residual heat removal service water and emergency service water systems.

The safety function of these valves is only to maintain pressure boundary.

The qualification analyses were performed using higher-than-requir ed acceleration g levels as shown on the piping analysis data sheets attached to the SgRT forms.

This is acceptable to the staff.

Susquehanna SSER 6

3-2

(10) Diesel Generator Fuel Oil Heat Exchanger

- In a recent review of the diesel 'generator qualification documentation by the applicant, it was found that this equipment was not addressed.

gualification of this equipment will be completed prior to fuel loading, which is acceptable to the staff.

3. 10. 1.2 New Field-Procured Equipment The following additional field-procured equipment has been added to BOP panels and will be added to the equipment list in the Equipment gualification Summary Report.

Reactor Core Isolation Cooling Backup Power Supply and Inverter - This equipment has been installed in the loose parts monitoring panel.

guali-fication documentation has been procured.

The test response spectra (TRS) will be compared with the in-panel RRS and if no exceedances

exist, the documentation will be completed by fuel loading.

In the meantime, the justification for interim operation up to 5X power level has already been provided and found acceptable to the staff.

The staff acceptance is based on the fact that the devices ar'e in operation only for shutdown at the remote shutdown panel (RSP) and that shutdown at the RSP is required only when evacuation on the control room is required.

(2)

ITE Overcur rent Relay (E109) - The relay has been relocated to the building wall adjacent to the panel where the corresponding RRS is enveloped by the TRS.

Review of the test report and update of the SgRT documentation has been completed.

This is acceptable to the staff.

(3)

Surge Arrestor - This device has passed dynamic qualification testing.

The test report and SgRT form have been added the existing SgRT documenta-tion of the host panels.

This is acceptable to the staff.

3.10.2 Nuclear Steam Supply System Equipment

3. 10.2. 1 Confirmatory Equipment Confirmatory analysis of the 'hydraulic control unit (HCU) is being performed'o verify that the relatively high TRS achieved in the dynamic testing of the skid assembly resulted in a response at the attachment points that exceeds that of the installed equipment.

Response

spectra at the two HCU upper-support points will be calculated and compared with those achieved at the same loca-tions during testing of the HCU s'kid.

Verification and final'gRT documenta-tion are to be completed before fuel loading.

3.10.2.2 Unit 2 Different Equipment The following Unit 2 NSSS equipment is different from that in Unit 1:

(1)

Power Range Detector - The power range detector provides safety function only for control rod drop accidents.

Should the power range monitors fail to provide a scram signal, the initial power excursion is terminated by the Doppler coefficient, and a backup scram signal is generated by closure of the main steam isolation valves on detection of high radioactivity in Susquehanna SSER 6

3-3

the main steamlines.

Therefore, failure of these components will not pre-clude the ability to accomplish or maintain cold shutdown.

r On the basis of the above, the staff finds interim justification to be acceptable for operation until the Unit 1 first refueling outage.

(2)

Architect/Engineer (A/E)-Added Devices to NSSS Panels A dynamic test has been completed to qualify all of these panel devices with the excep-tion of the Agastat ETR and

.TDPU relays, the TEC-indicating LED, the Simmons display module, the Validyne TMS module, and two HFA relays that are mounted to local racks.

These auxiliary relays provide control functions in their particular circuits, which include providing permissive signals to the control cir-cuits, signal initiation, and contact multiplication for adding duplicate signals to other circuits.

The timing relays (ETRs) perform similar functions with load sequence timing.

These relays have been qualified for significant levels of seismic and hydrodynamic excitation and are in use in other panels in the control room or relay room.

The NSSS panels, to which these relays have been

added, are generally of stiffer construc-tion in terms of panel skin thickness and frame members than the other panels for which in-panel response spectra were calculated and later used as RRS for device qualification.

The peak accelerations of the NSSS panels are shown in the addendum to the September 9,

1983 submittal and are compared with the zero period acceleration (ZPA) level of the TRS used to qualify the relays.

The.

actual panel g levels at the relay locations are expected to be signifi-cantly lower because the relays are typically installed in the lower two-thirds of the panels and the peak g levels are conservatively based on the product of the floor ZPA and transmissibility of the panel as measured in a low level sine sweep.

On the basis of the above reasoning, the staff finds them acceptable for interim operation before 5X power operation is exceeded while the actual NSSS in-panel RRS undergo calcula-tion in a program being implemented by PP8 L.

(3)

New Local Panel Devices - qualification of these devices has been com-pleted and has been included with the SgRT forms for NSSS local racks.

This is acceptable to the staff.

(4)

In-Vessel Rack - gualification of the rack is to be accomplished by strengthening of the welds at the rack support points..

A cable also will be added to prevent the rack from tipping if the rack is in use during a seismic event.

The rack is used only during refueling, and there may be an alternative to refueling without using the rack.

On the basis of, the above, the staff determines that interim operation until the Unit 2 first refueling outage while the rack is being qualified is acceptable.

(5)

Signal Resistive Units This equipment has been qualified with complete documentation and is acceptable to the staff.

Susquehanna SSER 6

3-4

(6)

Valcor Control Rod Drive Pilot Solenoid Valves - Valcor model V70900-45 pilot solenoid valves are used in place of the ASCO model 8323 valves in Unit 1.

The valve qualification is scheduled for completion by fuel loading.

Standby Liquid Control (SLC) Explosive Valve - The valve has no moving

parts, and was found to be rigid by testing to 35 Hz and by analysis to 60 Hz. It has successfully passed multiaxis, single-frequency dynamic testing to input g levels of 6.5 g and 4.5 g in horizontal and vertical directions, respectively, which are much higher than the corresponding required.input motion of 1. 1 g and 0. 8 g, and the explosive charge was fired during the test.

In addition, the maintenance and surveillance re-quirements for this valve are addressed in the plant Technical Specifica-tions, Section 3/4.1.5.

Electrical continuity is checked every 31 days, and the valve explosive charge is fired and replaced every 18 months.

(8)

On the basis of the above, the staff finds the qualification of this valve to be acceptable.

Main Steam Isolation Valve-Leakage Control System (MSIV-LCS) Heater - This heater has been qualified by comparing the response of the Unit 2 heater in the as-built piping system with the dynamic test environment of 6 g horizontal and 4 g vertical (ZPA) imposed on the heater specimen in the Unit 1 qualification test program.

Specifically, the maximum acceleration level required of the Unit 2 heaters was found to be 2.3 g, which is below the above ZPAs.

3. 10.2.3 Unit 1 Common Equipment The following is a list of NSSS equipment that is common for both Units 1

and 2.

(2)

Power Range Monitor Panel -

On the basis of the same-system-function argument of interim justification of Unit 1 operation, as stated in Supplement 4, the staff concluded that Unit 2 operation without a fully qualified PRM cabinet is acceptable until the Unit 1 first refueling outage.

Level Switches (E41-N014,

N002, N003,

N015, N018) - These devices have been qualified with complete documentation and are acceptable to the staff.

(3)

(4)

Condensate Storage Tank - Preliminary structural analysis of the tank indicates that the stresses are within allowable limits.

Final qualifi-cation will be completed before fuel loading.

High-Pressure Coolant Injection (HPCI) Turbine,- qualification documenta-tion is complete for the turbine.

The Unit 1 planned field modification,

however, has not been completed.

Because a redundant, single-failure-proof equipment path exists, which provides safe shutdown without HPCI (see Supplement 4), the applicant's justification for Unit 2 interim operation until the Unit 1 first refueling outage while the modification is being completed is acceptable to the staff.

Susquehanna SSER 6

3-5

(5)

Control Rod.Drive Vent and Drain Valves - Dynamic testing and in-pipe RRS calculation, together with qualification documentation, have been completed for both Unit 1 and 2 equipment.

The staff finds it to be acceptable.

3. 10.3 Fatigue Cycling Effects Due to Safety/Relief Valve (SRV) Loading The applicant's submittal of June 9, 1983, addressed the staff concern regarding the fatigue cycling effects on NSSS equipment resulting from SRV loads.

On the basis of an environment of 1,800 and 3,600 significant stress cycles as defined by -the applicant for equipment outside and inside containment, respectively, the maximum cumulative usage factor among equipment analyzed was calculated to be

0. 33, which occurred on the reactor core isolation cooling pump holddown bolts.

Supporting data were also provided by the applicant for equipment whose fatigue life adequacy was demonstrated using methods of extended duration testing.

For the MSIV-LCS blower, the total test time was 40 minutes and was achieved by four upset condition tests for 5 minutes each at 2-g input and four faulted condition tests for 5 minutes each at 3-g input.

These g levels are far in excess of the

0. 11-g ZPA of the required SRV spectra.

A sine sweep test method was performed in the frequency range of interest in which several thousand cycles minimum per each 5-minute test was imposed on the test specimen so that the cumulative number of cycles greatly exceeded the required 3,600 cycles stated previously.

Neither structural nor operability failure occurred during tPis testing.

Similar extended duration tests were performed for a number of other equipment

items, using either a biaxial sine sweep input, a multifrequency biaxial input motion, or two biaxial time history input motions.

The equipment items covered are 4. 16-kV switchgear, 125-Vdc power distribution panel, power range monitor-ing cabinet, valve motor operators, and MSIV actuator.

In all cases, both structural integrity and operability of the equipment were demonstrated during and after the test input motions.

On the basis of the above information provided by the applicant, the staff con-

, cludes that all NSSS equipment will perform satisfactorily under the fatigue cycling effects resulting from SRV loads.

3. 10. 4 Summary Section

3. 10. 1 describes the qualification status of Unit 2 BOP equipment that is different from that in Unit 1.

Section

3. 10. 2 describes the qualification status of Unit 2 NSSS equipment that is either different from that of Unit 1, is common with Unit 1, or simply is the one whose qualification needs confirma-tion.

As a result of the above evaluation, the following are actions that must be taken by the applicant.

(1)

Before Unit 2 fuel loading, the applicant should ensure full qualification and documentation as well as installation.of (a) vacuum relief valves (b) diesel generator fuel oil heat, exchanger (c) hydraulic control unit (d)

Valcor control rod drive pilot, solenoid valves (e) condensate storage tank Susquehanna SSER 6 6

(2)

Before~Unit 2 exceeds 5X power operation, the applicant should ensure full qualification and 'documentation as well as installation of (a) reactor core isolation cooling backup power supply and inverter (b)

A/E-added devices to NSSS panels, as identified in Section

3. 10. 2. 2 (3)

Before Unit 1 returns to operation after the first refueling outage, the applicant sh'ould ensure full qualification and documentation as well as install'ation of (a) power range detector (b) power range monitor panel (c) high-pressure coolant injection turbine (4)

Before the Unit 2 first refueling outage, the applicant should ensure full qualification and documentation as well as installation of the in-vessel rack.

3. 11 Environmental uglification

3. 11. 1 Environmental gualification of Safety-Related Electrical Equipment Equipment that is used to perform a necessary safety function must be demon-strated to be capable of maintaining functional operability under all service conditions postulated to occur during its installed life for the time it is required to operate.

This requirement, which is embodied in GDC 1 and 4 of Appendix A and Sections III, XI, and XVII of Appendix B to 10 CFR 50, is applicable to equipment located inside as well as outside containment.

More detailed requirements and guidance relating to the methods and procedures for demonstrating this capability for electrical equipment have been set forth in 10 CFR 50.49, "Environmental gualification of Electric Equipment Important to Safety for Nuclear Power Plants";

NUREG-0588, "Interim Staff Position on Environmental gualification of Safety-Related Electrical Equipment," which supplements IEEE Std 323; and various NRC regulatory guides and industry standards.

3. 11. 2

Background

NUREG-0588 was issued in December 1979 to promote a more orderly and systematic implementation of equipment qualification programs by industry and to provide guidance to the NRC staff for its use in ongoing licensing reviews.

The posi-tions contained in that report provide guidance on (1) how to.establish environ-mental service conditions, (2) how to select methods that are considered appro-priate for qualifying equipment in different areas of the plant, and (3) other areas such as margin, aging, and documentation for each item of safety-related electrical equipment and to identify the degree to which their qualification programs complied with the staff positions discussed in NUREG-0588.

IE Bulletin 79-01B, "Environmental gualification of Class 1E Equipment,"

issued January 14, 1980, and its supplements dated February 29, September 30, and October 24, 1980, established environmental qualification requirements for op-erating reactors.

This bulletin and its supplements were provided to operating license applicants for consideration in their review.

Susquehanna SSER 6

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A final rule on environmental qualification of electrical equipment inportant to safety for nuclear power plants became effective February 22, 1983.

This

rule, 10 CFR 50.49, specifies the requirements to be met for demonstrating the environmental qualification of electrical equipment important to safety located in a harsh environment.

In accordance with 10 CFR 50.49, electrical equipment at Susquehanna may be qualified in accordance with the acceptance criteria specified in Category II of NUREG-0588.

To document the degree to which the environmental qualification program com-plies with the NRC s environmental qualification requirements and criteria, the applicant provided equipment qualification information by letters dated June 20, 1983, November 3, 1983, December 21 and 30, 1983, January 5, 1984, and January ll, 1984.

3. 11. 2. 1 Purpose The purpose of this supplement is to evaluate the adequacy of the Susquehanna environmental qualification program for electrical equipment important to safety as defined in 10 CFR 50.49.

The staff position relating to open items, as well as any unresolved

issues, is provided in this report.

3. 11. 2. 2 Scope The scope of this report is limited to an evaluation of the electrical equip-ment important to safety at Susquehanna Unit 2 that is different from electrical equipment at Unit 1 and that must function to mitigate the consequences of a design-basis

accident, inside or outside containment, while subjected to the hostile environments associated with these accidents.

Electrical equipment at Unit 2 that is identical to equipment at Unit 1 was addressed in Supplements 3 and 4.

3.11.3 Staff Evaluation The staff evaluation of the applicant's Equipment Environmental qualification (EEg) submittal dated September 9, 1983, includes a review of the following equipment items that have been identified by the applicant as items installed or to be installed at Unit 2 that are not identical to items installed at Unit l.

Item descri tion Manufacturer Model no.

Cable specialty DX refrigeration system Rockbestos American Air Filter RSS-6-XXX Resistance temperature detector Conax 7349-10000-01 Transmitter (pressure and level)

ITT Barton

763, 764 Susquehanna SSER 6

3-8

Item descri tion Manufacturer Model no.

Target Rock In submittals dated September 9, 1983, and January 5 and ll, 1984, the 'applicant identified 'items 1, 3, and 4 as being qualified for their application.

Item 5 will be qual Hied by May 1984.

The applicant has provided a justification for interim operatio'n 'for item 5.

The staff finds the justification acceptable.

Item 2 will be completely qualified after the replacement of the water regulat-ing valve.

The applicant has committed to replace the valve with a qualified valve before fuel loading.

The applicant should confirm, before the granting of the operating license, that the valve has been replaced with a qualified valve or provide a justification for interim operation.

Also in accordance with the latest information available to the staff, the validity of the test report for Rockbestos

cable, item 1, is in doubt.

However, on the basis of other information 'available to the staff (results of testing performed on Rockbestos cable by both the Franklin Research Center and Sandia),

the staff concludes at this time that no safety problem exists because of the use of this cable.

An information notice is being prepared by the NRC Office of Inspection and Enforcement concerning this issue.

It will be the applicant's responsibi-lity to evaluate'the information in that information notice for applicability to his facility and to take appropriate action to ensure that the documentation relied on to demonsti ate environmental qualification of Rockbestos cable sup-ports such a conclusion.

The open item identified in Section

3. 11. 1 of Supplement 5 involves compliance with 10 CFR 50. 49(b).'n the submittal of September 9, 1983,'he applicant confirmed that all safety-related electrical equipment within the scope of 10 CFR 50.49 has been included in the qualification program.

The applicant also stated that there is no nonsafety-related electrical equipment located in a harsh environment whose failure under postulated accident conditions could prevent satisfactory accomplishment of a safety function by safety-related equipment.

In a letter dated June 20, 1983, the applicant referenced FSAR Sections 3.12 and 8.1.6, which define his criteria for physical separation and electrical isolation between safety and nonsafety-related equipment.

These FSAR sections also discuss compliance with Regulatory Guide 1.75.'he staff had previously reviewed these FSAR sections and found them acceptable.

The applicant has not,

however, provided an evaluation of the effects of high energy line breaks on control systems.

Hence, the staff cannot conclude that the failure of nonsafety-related equipment will not prevent safety-related equipment from performing its function.

However, in a letter dated December 21, 1983, the applicant committed to provide this information before 5X power is exceeded.

The applicant has provided justification for interim operation up to 5X power.

This justification is based on the fact that the only activity planned during this period is low power physics testing.

The reactor coolant system nuclear fission inventory and residual heat will be sufficiently low so as to preclude any significant effects on the electrical equipment in question should an accident occur.

The staff concurs with the applicant s justification and, on the basis of this, issuance of an operating license for up to 5X power is acceptable.

In letters dated June 20, 1983, and December 30, 1983, the applicant also addressed compliance with Regulatory Guide 1.97, Revision 2.

The applicant has Susquehanna SSER 6

3-9

qualified all equipment considered to be Category I or II in accordance with his position contained in PLA-965, dated November 13, 1981, except for the ex-core neutron monitoring system.

For this system, there are two items of equip-

ment, Conax connectors and neutron sensors, for which testing has been success-fully'ompleted by the vendors and the qualification reports have been evaluated and approved by the architect/engineer.

However, the applicant,has not yet completed the review and evaluation in accordance with.his equipment qualifica-tion program.

The applicant expects to approve the qualification of this equip-ment during the first quarter of 1984.

This justification for interim operation is acceptable,to the staff.

On the basis of this, the staff concludes that the response to 10 CFR 50.49(b)(3) is acceptable.

h On the bas'is of the above, the staff concludes that all open items identified in Section 3.11 of Supplement 5 have been satisfactorily resolved except for the following confirmatory item:

(1)

The applicant should confirm, prior to the granting of an operating license, that the water regulating valve on the DX refrigeration unit has been replaced with a qualified valve.

The following license conditions should be incorporated into the Susquehanna Unit 2 license:

(1)

The applicant should provide the evaluation of the effects of high energy line breaks on control systems for staff review and approval before 5X power is exceeded.

(2)

All electrical equipment within the scope of 10 CFR 50.49 should be environmentally qualified by March 31, 1985.

On the basis of the results of its,review and evaluation, and on satisfactory completion of the confirmatory item identified above, the staff concludes that the applicant has demonstrated compliance with the requirements of 10 CFR 50.49, the relevant parts of GDC 1 and 4 of Appendix A and Sections III, XI, and XVII of Appendix B to 10 CFR 50, and the criteria specified in NUREG-0588 for operation up to 5X of full power for Susquehanna Unit 2.

The staff con-cludes that a full-power license can be issued on satisfactory compliance with License Condition (1) above.

Susquehanna SSER 6

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4 REACTOR

4. 4 Thermal'nd H draulic Desi n

In Section

1. 10 of Supplement 5 to the SER, the staff provided a list of issues for which a condition was included in the operating license for Susquehanna Unit 1 for which a similar license condition would be required for Unit 2 unless satisfactory resolution was reached on the issue for licensing Unit 2.

One such issue regarded thermal and hydraulic design, specifically, natural circulation conditions and a new stability analysis at the end of the first fuel cycle indicating the results for appropriate exposure core conditions.

The staff recently became aware of new stability test data that demonstrated the occurrence of limit cycle neutron flux oscillations at natural circulation and several percent above the rated rod line.

The oscillations were observable on the average power range monitors (APRMs) and were suppressed with control rod insertion.

It was predicted that limit cycle oscillations would occur at the operating conditions tested;

however, the characteristics of the observed oscillations were different from those previously observed during other stabil-ity tests.

Namely, the test data showed that some local power range monitors oscillated out of phase with the APRM signal and at an amplitude as great as six times the core average.

The Unit 1 license condition on thermal and hydraulic design with regard to operation in natural circulation is not required on Unit 2 because the Tech-nical Specifications provide limiting conditions for operation in natural ci>

culation and with only one recirculation loop.

However, for the potential thermal-hydraulic instability described

above, the Technical Specifications are not sufficiently prescriptive.

PP&L in a letter dated March 15, 1984, com-mitted to provide, before exceeding 5X power on Unit 2, either a proposed change to Susquehanna Steam Electric Station Units 1 and 2 Technical Specifi-cations or an alternative resolution that is acceptable to the NRC staff.

This commitment is acceptable to the NRC staff because the thermal-hydrauli'c instability described above is not a safety concern at low power levels.

With regard to providing a new stabi.lity analysis at the end of the first fuel cycle indicating the results for appropriate exposure core condit'ions, the design criteria in Appendix A to 10 CFR 50 address the requirements for new stability analysis.

Therefore, a specific license condition to address this issue is not required.

4.6 Safet Concerns Associated With Scram Dischar e

S stem Pi in In Section 4.6 of Supplement 4 to the SER, the staff concluded that operation at full power for one fuel cycle with unqualified scram discharge volume (SDV) pipe break detection and mitigation equipment is acceptable.

The staff also concluded that if its review of the probabilistic risk assessment (PRA) sub-mitted by the applicant on August 25, 1982, showed that further protection from an SDV pipe break is required, then all equipment qualification had to be imple-mented before the end of the first refueling outage.

The staff's evaluation in Susquehanna SSER 6

4-1

Supplement 4 described the shutdown capability already existing at Susquehanna Unit 2 that formed the basis for allowing interim operation for one fuel cycle.

Additional information was submitted in GE Topical Report NEDO-22209.

NEDO-22209 updated the probabilistic approach. originally presented in the first PRA, NED0-,24342, and presented probabilistic arguments as an alternative to the criteria of NUREG-0803, Generic Safety Evaluation Report Regarding the Integrity of BWR Scram System Piping."

The staff reviewed NEDO-22209 and concluded that resolution of the concern required more detailed consideration of the applicable pipe break mechanisms than can be obtained by a probabilistic analysis.

Further specific information was requested regarding a deterministic fracture mechanics evaluation of'he scram system piping and discussions of the associated realistic leak rate, leak detection, and mitigation capability.

Since this is

a. multiplant item, these requests were transmitted to the BWR Owners Group by letter dated July 25, 198$.

By letter dated November 18, 1983, the BWR Owners Group provided responses to the additional requests for information except for one item that was plant specific regarding radiation exposure as a result of routine tests and inspec-tions.

The staff will review the BWR Owners Group responses and will provide a generic evaluation that identifies any additional design requirements developed as a result of its review.

The item regarding radiation exposure will be eval-uated on a case-by-case basis following completion of the generic evaluation.

Since this is a multiplant action item, the staff has not made a determination as to what design changes, if any, are necessary for Susquehanna Unit 2 until the review of the BWR Owners Group responses is complete.

The staff, therefore, concludes that the requirement for equipment qualification stated in Supple-ment 4 should be changed because this action is not governed by 10 CFR 50.49.

In a letter dated August 3, 1983, PP8 L committed to implement all actions and modifications specified in the generic SER regarding NUREG-0803 within 2 years after the'ssuance of the generic SER, or before the end of the first refueling outage after the issuance of the generic SER.

On the basis of the status of its review, the staff finds PP&L's commitment acceptable.

Susquehanna SSER 6

5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

5. 2 Inte rit of the Reactor Coolant Pressure Boundar

5. 2. 4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing GDC 32, "Inspection of Reactor Coolant Pressure Boundary," requires, in part, that components of the reactor coolant pressure boundary be designed to permit periodic inspection and testing of important areas and features to assess their structural and leaktight integrity.

To ensure that no deleterious defects develop during service, selected welds and weld heat-affected zones will be inspected periodically at the Susquehanna Steam Electric Station.

The design of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) Class 1 components of the reactor coolant pressure boundary in Susquehanna incorporates provisions for access for inservice examination in accordance with Section XI of the ASME Code.

Methods have been developed to facilitate the remote examination of these areas of the reactor vessel not readily accessible to examination personnel.

10 CFR 50. 55a(g) defines the detailed requirements for the preservice and in-service inspection programs for light-water-cooled nuclear power facility compo-nents.

On the basis of the construction permit date of November 2, 1973, this section of the regulations requires that a preservice inspection program be de-veloped and implemented using at least the Edition and Addenda of Section XI of the ASME Code in effect 6 months before the date of issuance of the construction permit, subject to the limitations and modifications listed in 10 CFR 50.55a(b).

Also, the initial inservice inspection program must comply with the require-ments of the latest Edition and Addenda of.Section XI of the ASME Code in effect 12 months before the date of issuance of the operating license, subject to the limitations and modifications listed in 10 CFR 50. 55a(b).

5.2.4.2 Evaluation of Compliance With 10 CFR 50.55a(g) for Unit 2 The staff completed the review of the Preservice Inspection (PSI) Program for Unit 1 and determined that this document was acceptable as described in Sec-tion 5.2.4. 1 of Supplements 3 and 4.

The pr eservice examination of Unit 2 was performed to the same ASME Code requirements (as modified by specific written relief requests) as the Unit 1 PSI Program with one exception; that is, although the manual ultrasonic data from the Unit 2 reactor vessel were collected before RG 1. 150, Revision 1, was issued, the remote automated ultrasonic testing of the Unit 2 reactor vessel did conform to RG 1. 150, Revision 1.

Therefore, the staff has determined that the PSI Program for Unit 2 is acceptable on, the basis of the staff review and acceptance of the corresponding document for Unit 1.

The staff has completed the review of requests for relief from certain require-ments that the applicant determined to be impractical in letters dated August 2,

1983, November 1, 1983, and December 21, 1983, in which a supporting technical justification was provided.

The staff has determined that certain ASME Code, Susquehanna SSER 6

5-1

Section XI,- examination requirements defined in 10 CFR 50.55a(g)(2) are imprac-tical.

Therefore, pursuant to 10 CFR 50.55a(a)(2),

the staff has allowed relief from the requirements that have been determined to be impractical and that if implemented would result in hardships or unusual difficulties without a compen-sating increase in the level of quality and safety.

On the basis of the grant-ing of relief from these preservice examination requirements, the staff con-cludes that the PSI Program for, Unit 2 is in compliance with 10 CFR 50.55a(g)(2).

A detailed evaluation supporting this conclusion is provided in Appendix H to this report.

The initial inservice inspection program for Unit 2 will be eval-uated after the applicable ASME Code edition and addenda can be determined based on 10 CFR 50.55a(b) and before the first refueling outage when inservice inspec-tions will be performed.

Periodic inspections and hydrostatic testing of pressure-retaining components of the reactor coolant pressure boundary in accordance with the requirements of Section XI of the ASME Code and 10 CFR 50 will provide reasonable assurance that evidence of structural degradation or loss of leaktight integrity occur-ring during service will be detected in time to permit corrective action before the safety functions of the components are compromised.

Compliance with the inservice inspections required by Section XI of the ASME Code and 10 CFR 50 constitutes an acceptable basis for satisfying the inspection requirements of GDC 32.

5.3 Reactor Vessel 5.3. 1 Reactor Vessel Materials The review requirements and conclusions that were discussed in the staff's safety evaluation of Susquehanna Unit 1 are applicable to Unit 2.

5.3. 1. 1 Compliance With Appendix G, 10 CFR 50 Appendix G requires that a reference temperature, RTNDT, be determined for each ferritic material of the reactor vessel and that this reference temperature be used as a basis for providing adequate margins of safety for reactor operation.

The value of RTNDT is defined in the ASME Code as the higher of either (1) the nil ductility temperature, as determined by the dropweight test, or (2) a tem-perature of 60F'ess than the temperature at which 50 ft-lb of energy and 35 mils of lateral expansion are achieved, as determined by the Charpy V-notch (CVN) impact test.

The CVN impact test is to be conducted using specimens oriented in the transverse direction.

Unit 2 material tests were performed to meet the requirements of the 1968 Edition, including the Summer 1970 Addenda,Section III of the ASME Code.

The applicant stated that to demonstrate com-pliance with the requirements of Appendix G, 10 CFR 50, RTNDT values have been defined using existing impact test data in conjunction with various data corre-lations to establish the temperature at which 50 ft-lb of energy is achieved for specimens oriented in the transverse direction.

The staff has evaluated the applicant's methods of determining the RTNDT and has conCluded that the method used by the applicant will provide a conservative estimate of the RTNDT.

Paragraph IV.A.1 of Appendix G, 10 CFR 50, requires, in part, that the reactor vessel beltline materials have Charpy upper-shelf energy of no less than Susquehanna SSER 6

5-2

75 ft-lb initially and must maintain upper-shelf energy throughout the life of the vessel of no less than 50 ft-lb, unless it is demonstrated in a manner approved by NRC, that lower values of upper-shelf energy we'll provide margins of safety against fracture equivalent to'those required by Appendix G of the ASME Code.

All beltline materials in Unit 2 meet these requirements except for two weld materials (heat nos.

624263 and 09M057) and four plates (heat nos.

6C1053/1, C2421/3, C2929/1, and C2433/2).

These materials were not Charpy tested at high enough temperatures to determine their upper shelf.

The applicant has provided Charpy upper-shelf data from other welds and plates that'ere fabricated using the same process and heat treated to a microstruc-ture equivalent to that of Unit 2 welds and plates.

These data indicate that had the Unit 2 weld and plate materials been tested <at higher temperatures, their upper-shelf energies would exceed the req'uirements of Paragraph IV.A.1 of Appendix G, 10 CFR 50.

Hence, the staff considers that all Unit 2 reactor vessel beltline materials will have adequate upper-shelf energies throughout the design life of the vessel.

All Unit 2 ferritic main steam piping and valve materials have been tested to meet the requirements of Appendix G except for the main steam isolation valve (MSIV) body and bonnet materials.

Appendix G, 10 CFR 50, requires that these materials be tested to the requirements of the ASME Code.

The current ASME Code requirement is that the MSIV body and bonnet materials must be CVN impact tested at the lowest service metal temperature and that the CVN lateral expan-sion must exceed 25 mils.

The applicant has indicated that the lowest service metal temperature is 60'F.

This temperature is conservative because significant pressure is not applied to the MSIV during operation until the boiling point of water (212'F) is reached.

The applicant's ferritic reactor coolant pressure boundary materials in the MSIV were not CVN impact tested because they were fabricated to an earlier Code, which did not require CVN impact testing.

The applicant has supplied CVN impact data for MSIV materials from other nuclear facilities that had been fabricated to the same specification and heat treated

to an equivalent metallurgi'cal cqndition as the Unit 2 ferritic valve materials.

The data indicate for the ferritic MSIV body and bonnet materials that CVN lateral expansion at 60'F test temperature would exceed 25 mils.

Hence, the staff con-siders that these materials will have adequate toughness.

5.3.1.2 Compliance With Appendix H, 10 CFR 50 The toughness properties of the reactor vessel beltline materials will be monitored throughout the service life of Unit 2 by a materials surveillance program that must meet the requirements of Appendix H, 10 CFR 50, and, there-fore, also the requirements of American Society for Testing and Materials (ASTM) Std E 185-73, "Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels."

The staff has evaluated the applicagt's information for degree of compliance to these Vequirements and has concluded that the appli-cant has met all the requirements of Appendix H, 10 CFR 50, except for Para-graph II.B.l.

Paragraph II.B.1 requires that the number of Charpy test speci" mens and the orientation of the test specimens for the Unit 2 reactor vessel surveillance program must comply with the requirements of ASTM Std E 185-73.

ASTM Std E 185-73 requires that there be a minimum of 12 Charpy test specimens Susquehanna SSER 6

5-3

for each base metal, weld metal, and heat-affected-zone (HAZ) sample in each capsule and that the base metal specimens be removed from the plate with their major axis normal (transversely) to the rolling direction of the plate.

The minimum number of weld metal, base metal, and HAZ specimens contained in a Unit 2 surveillance capsule is eight, and the plate test specimens were removed from the plate with their major axes parallel (longitudinal) to the rolling direction of the plate.

Although the minimum number of specimens is not contained in each capsule and the plate test specimens orientation is in the longitudinal direction, the test data obtained should provide sufficient information to predict the relative shift in RTN>T as a result of neutron irradiation.

The staff s conclusion is based on its experience that the relative shift is not greatly sensitive to specimen orientation and that the amount of shift in RTNDT may be estimated from the testing of eight specimens.

On the basis of its evaluation of the Unit 2 surveillance

program, the staff concludes that there is reasonable assurance that the surveillance program will monitor the change in the beltline region to a degree adequate to determine the pressure-temperature limits to preserve the integrity of the vessel.

The pro-gram will generate sufficient information to permit the determination of condi-tions under which the reactor vessel will be operated with an adequate margin of safety against rapidly propagating fracture throughout its service lifetime.

5.3.'.3 Conclusions for Compliance With Appendices G and H,

10 CFR 50 The Unit 2 reactor vessel and other reactor coolant pressure boundary components were constructed to an ASME Code that was earlier than the Summer 1972 Addenda of the 1971 Edition.

Hence, the materials that were used in the fabrication of these components were not tested to the extent required by Appendices G and H,

10 CFR 50.

However, for reactor vessel and other reactor coolant pressure bound-ary materials that were constructed to an ASME Code earlier than the Summer 1972 Addenda of th'e 1971 Edition, Appendices G and H, 10 CFR 50, permit the NRC to approve alternative fracture toughness test methods other than those required by the appendices.

The staff has evaluated the applicant's alternative fracture toughness test program and methods of demonstrating that the materials comply with the intent of Appendices G and H, 10 CFR 50.

The staff considers the appli-cant's alternative fracture toughness test program acceptable, and that the materials used in the fabrication of the reactor vessel and other reactor cool-ant pressure boundary components will meet the minimum fracture toughness re-quirements of Appendices G and H, 10 CFR 50, through the plant's design life of 32 effective full-power years (EFPYs).

Appendix G, "Protection Against Nonductile Failure,"Section III of the ASME Code, will be used with fracture toughness test results required by Appendices G

and H, 10 CFR 50, to calculate the reactor coolant pressure boundary pressure-temperature limits for Unit 2.

The fracture toughness tests required by the ASME Code and Appendix G, 10 CFR 50, will provide reasonable assurance that adequate safety margins against the possi-bility of nonducti le behavior or rapidly propagating fracture can be established for all pressure-retaining components of the reactor coolant pressure boundary.

The use of Appendix G,Section III of the ASME Code, as a guide in establishing 1

Susquehanna SSER 6

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safe operating procedures, and the use of the results of the fracture toughness testa performed in accordance with the ASME Code and NRC regulations will pro-vide 'adequate safety margins during operating, testing, maintenance, and anti-cipated transient conditions.

Compliance with these Code provisions and NRC regulations constitutes an acceptable basis for satisfying the requirements of GDC 31.

The material surveillance

program, required by Appendix H, 10 CFR 50, will pro-vide informa'tion on, material properties and the effects of irradiation on the material properties so that changes in the fracture toughness of material in the Unit 2 reactor vessel beltline region caused by neutron radiation can be properly assessed, and adequate safety margins against the possibility of ves-sel failure can be provided.

Compliance with ASTM Std E 185-73 and Appendix H, 10 CFR 50, satisfies the requirements of GDC 31 and 32.

5.3 '

Pressure-Temperature Limits Appendix G, "Fracture Toughness Requirements,"

and Appendix H, "Reactor Vessel Material Surveillance Program Requirements,"

10 CFR 50, describe the conditions that require pressure-temperature limits for the reactor coolant pressure boundary and provide the general bases for these limits.

These appendices specifically require that pressure-temperature limits must provide safety mar-gins for the reactor coolant p'ressure boundary at least as great as the safety margins recommended in the ASME Code,Section III, Appendix G.

Appendix G, 10 CFR 50, requires additional safety margins for the closure flange region and for the beltline r'egion whenever the reactor core is critical, except for low-level physics tests.

The following pressure-temperature limits imposed on the"'reactor coolant pres-sure boundary during operation and tests are reviewed to ensure that they pro-vide adequate safety margins against nonductile behavior or rapidly propagat-ing failure of ferritic components as required by GDC 31:

(1) preservice hydrostatic tests (2) inservice leak and hydrostatic tests (3) heatup and cooldown operations (4) core operation Appendices G and H, 10 CFR 50, require the applicant to predict the shift in reference temperature resulting from neutron irradiation.

The shift in RTNDT resulting from neutron irradiation is then added to the initial RTNDT to estab-lish the adjusted reference temperature.

The base plate or weld seam having the highest adjusted reference temperature is considered the most limiting beltline material on which the pressure-temperature operating limits are based.

In the case of Unit 2, the limiting beltline material would be plate I.D.21-3.

The applicant in FSAR Figure 5.3-4b has provided pressure-temperature limit curves for Unit 2.

The length of time these curves are acceptable depends on the amount of neutron irradiation damage predicted for the limiting Unit 2 beltline material.

The staff uses Regulatory Guide 1.99, "Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel Materials," to predict the amount of neutron irradiation damage.

The staff's evaluation of the effect Susquehanna SSER 6

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of neutron -irradiation damage on the limiting beltline material, indicates that the curves identified as A, B, and C in FSAR Figure 5.3-4b are acceptable for 15 EFPYs and curves identified as A', B', and C're acceptable for 32 EFPYs.

Revision to 10 CFR 50, Appendix G, was published in the Federal Re ister on May 27, 1983, and became effective on July 26, 1983.

The amended Appendix G, 10 CFR 50, states that when pressure exceeds 20'f the preservice system hydrostatic test pressure, the temperature of the closure flange regions that are highly stressed by bolt preload must exceed the reference temperature of the materials in those regions by at least 120F for normal operation and by 90F for hydrostatic pressure tests and leak tests, unless a lower temperature can be justified by showing that the margins of safety for those regions, when they are controlling, are equivalent to those required for the beltline, when it is cont>oiling.

The applicant's pressure-temperature limit curves do not meet the pressure-temperature margins for the closure flange region defined in the amended Appendix G, 10 CFR 50.

The staff will be implementing those requirements in. a 10 CFR 50.54(f) letter, which will be sent to all licensees of operating reac-tors, applicants for operating licenses, and holders of construction permits.

The staff will complete its review of the applicant's pressure-temperature limits when it has completed the implementation of the 10 CFR 50.54(f) letter, which will be sent to the applicant.

The pressure-temperature limits to be imposed on the reactor coolant system for all operating and testing conditions to ensure adequate safety margins against nonductile or rapidly propagating failure must be in conformance with established criteria,

codes, and standards acceptable to the staff.

The use of operating limits based on these criteria, as defined by applicable regula-

tions, codes, and standards, will provide reasonable assurance that nonductile or rapidly propagating failure will not occur and will constitute an acceptable basis for satisfying the applicable requirements of GDC 31.'.3.3 Reactor Vessel Integrity The staff has reviewed the FSAR sections related to the reactor vessel integrity of Unit 2.

Although most areas are reviewed separately in accordance with other review plans, reactor vessel integrity is of such importance that a special summary review of all factors relating to reactor vessel integrity is warranted.

The staff has reviewed the information in each area to ensure that it is complete and that no inconsistencies exist that would reduce the certainty of vessel integrity.

The areas reviewed are:

(1) design (SER Section 5.3. 1)

(2) materials of construction (SER Section 5.3. 1)

(3) fabrication methods (SER Section 5.3. 1)

(4) operating conditions (SER Section 5.3.2)

The staff has reviewed the above factors contributing to the structural integrity of the reactor vessel and concludes that the applicant has complied with,Appen-dices G and H, 10 CFR 50, except for the following items:

Susquehanna SSER 6

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(1)

(2)

All ferritic reactor vessel materials were not sufficiently tested to determine the'ir RTN>T.

The applicant has provided alternative methods for determining the RTNDT for each ferritic reactor vessel material.

The staff has evaluated the applicant' methods of determining the RTNQT and has concluded that the methods used by the applicant will provide a con-servative estimate of the RTN>T.

All beltline materials were not Charpy tested at high enough temperatures to determine whether their upper shelf would meet the requirements of Paragraph IV.A.1 of Appendix G, 10 CFR 50.

The applicant has provided Charpy upper-shelf data from other welds and plates to demonstrate that all beltline materials meet the Charpy upper-shelf requirements of Appen-dix G, 10 CFR 50.

The staff has reviewed the Charpy data provided by the applicant and has concluded that all reactor vessel beltline materials will have adequate upper-shelf energies throughout the design life of the vessel.

(3)

(4)

The MSIV body and bonnet materials were not Charpy tested.

However, the applicant has provided alternative Charpy test data that indicate the MSIV body and bonnet materials have adequate toughness.

The applicant's reactor vessel material surveillance program does not contain test specimens that meet the orientation and minimum number re-quirements of ASTM Std E 185-73.

However, the staff has evaluated the applicant's surveillance program and has concluded that it is adequate for determining the amount of change in RTN>T for the Unit 2 beltline materials.

(5)

The applicant's pressure-temperature curves do not meet the pressure-temperature margins for the closure-flange region identified in the revised Appendix G, 10 CFR 50, which was published on May 27, 1983.

The staff will be implementing those requirements in a 10 CFR 50.54(f) letter, which will be sent to all applicants for operating licenses.

The staff will complete its review of the applicant's pressure-temperature limits when it has completed the implementation of the 10 CFR 50.54(f) letter.

The staff has reviewed all factors contributing to the structural integrity of the Unit 2 reactor vessel and concludes that there are no'pecial con-siderations that make it necessary to consider potential reactor vessel failure.

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6 ENGINEERED SAFETY FEATURES 6.2 Containment S stems 6.2.1 Containment Functional Design 6.'2.1.8 Pool

Dynamics, 6.2. 1.8.g(5)

Pool Temperature Limit In Section 6.2.1.8.g(5) of the SER for the Susquehanna Steam Electric Station, Units 1 and 2, the applicant committed to use data from a comprehensive safety relief valve inplant test that is to be completed before the start of commercial operations at the La Salle facility.

The applicant also committed to use the information from these tests to establish the value between local and bulk pool temperatures to demonstrate that a maximum local pool temperature specification of 200 F as specified in NUREG-0487 will not be exceeded.

Since the issuance of the SER, the Mark II Owners Group proposed alternative suppression pool limits.

The alternative limits, which are applicable to Susquehanna

.Steam Electric Station, Units 1 and 2, are contained in NUREG-0783 and supersede the criteria contained in NUREG 0487.

In a letter dated November 21, 1983, the applicant submitted a report entitled "Evaluation of the NUREG-0783 Local Pool Temperature Limits for the Susquehanna Steam Electric Station."

The applicant concluded that the local pool tempera-ture limits stipulated in NUREG-0783 for all plant transients involving safety relief valve actuations will not be exceeded.

The staff evaluation of this report is ongoing;

however, the staff's preliminary assessment has confirmed the applicant's conclusion.

Therefore, this issue is now considered a confirm-atory item.

Upon completion of the staff review, the results and bases of its evaluation will be documented in a future safety evaluation.

6. 2. 1.8. h Wetwell/Drywell Vacuum Breakers The Susquehanna Steam Electric Station (SSES) containment is equipped with

simple, swing check valves, which serve as vacuum breakers to equalize the pressure between the drywell and wetwell air space regions so that the reverse direction pressure across the diaphragm floor will not exceed the design value.

The vacuum relief valves (five assemblies) are mounted on selected downcomers inside the suppression pool air space region.

Following the onset of a loss-of-coolant accident and during the pool swell phase, air flows from the drywell through the vent pipes and the suppression pool into the suppression pool chamber air space resulting in a rise of the sup-pression pool surface and compression of the air space region above it.

This transient wetwell air space pressurization may cause the vacuum breaker valves to experience high opening and closing impact velocities.

To estimate the valve disc actuation velocities, the Mark II Owner's Group developed a vacuum breaker valve dynamic model (NEDE-22178-P (General Electric Company)),

which was submitted for review by the staff.

Susquehanna SSER 6

The staff has completed its review of NEDE-22178-P, which describes the generic methodology used to calculate the response of the drywell-to-wetwell vacuum breaker to certain transients in the Mark II containment, and found the approach acceptable.

The applicant indicated that use of this model will lead to predictions of very conservative impact velocities during pool swell transients because the hydro-dynamic torque generated on the valve disc as a consequence of the pool swell differential pressure upstream and downstream of the valve very conservatively bounds full-scale test data.

Recognizing the above, the SSES applicant along with the applicants for Shore-ham and Limerick initiated an effort to predict more realistic yet conservative impact velocities for use in the qualification of the vacuum breaker valves.

'L During a meeting held on June 7, 1983, in Bethesda, Maryland, between the staff and the applicants for Shoreham, Susquehanna, Limerick, and WNP-2, a presen-tation was made of the analysis and redesign that produced a reduction in the valve impact velocities during pool swell.

The material presented during that meeting is documented in a letter dated June 17, 1983,, from Bechtel Power Corporation.

Reduction of the valve impact velocities during pool swell is attributed to the use of more realistic hydrodynamic torque on the valve disc.

The applicant stated that the hydrodynamic torque specified in NEDE-22178-P is extremely conservative.

Therefore, the applicant proposed a reduction of conservatism in the hydrodynamic torque as a function of valve opening angle and demonstrated

that, even with the proposed reduction implemented in the model described in NEDE-22178-P, the predictions of disc impact velocity are conservative when compared with test data.

The staff reviewed the applicant's submittals and concludes that the proposed reduction of the hydrodynamic torque is reasonable and, therefore, acceptable.

Several changes were made to the valve design, which contributed to a reduction of the impact velocities and to the strength of the valve for withstanding these impact velocities.

The changes encompass the requirements specified in License Condition 2.C.(16) in Susquehanna Steam Electric Station Unit' Operating License No.

NPF-14 and include redesign of the spring cylinder linkage (single-'ar linkage instead of four-bar linkage); incorporation of an actuating cylinder (double-cylinder modification) for damping; changes for a higher spring constant, thicker dome, and ring flange; use of an internal stop; replacement of the shaft,

keys, and pivot arm with higher strength materials; and a change to increase the shaft bearing area.

The predicted pallet impact velocities for the modified valve (using the dynamic model described in NEDE-22178-P, time-dependent differential pressure loading across the vacuum breaker disc derived from the 4TCO test data and adjusted to a peak value of 5.5 psid as recommended in NUREG-0808, and the mean hydrodynamic torque) are an opening impact velocity of less than 1 radian/sec and a closing impact velocity of 5.8 radian/sec.

The modified vacuum breaker was subjected to opening and closing impact veloc-ities higher than the predicted impact velocities.

Post-test visual inspection Susquehanna SSER 6

6-2

and leakage.test show that valve operability and 'integrity as a pressure

,boundary are maintained and, therefore, the wetwell-to-drywell vacuum breaker valves will perform their function following the onset of a LOCA.

As analysis was performed for the Shoreham (opening impact velocity of 12.7 radian/sec and closing impact velocity of 10.9 radian/sec) modified vacuum breaker design to verify the valve's structural and pressure integrity.

A linear elastic analysis was used for the evaluation of all valve components.

An additional plastic analysis was performed to evaluate the structural integ-rity of the "spiders" for the pool-swell impact loadings.

The spiders are spokes that are radially mounted on the valve disc and are designed 'as energy-absorbing members to absorb'he energy associated with the disc impact loads.

The loads and load combinations were reviewed and found to be in accordance with

,the staff's acceptance criteria.

The loads were combined using the methodology in NUREG-0484, Revision 1, "Methodology for Combining Dynamic Responses."

The resulting stresses in the primary pressure-retaining boundaries were within the American Society of Mechanical Engineers "Boiler and Pressure Vessel Code" (ASME Code),

Class 2 faulted allowable limits (Service Level D).

The resulting stresses in the, shaft, linkage, and spring cylinder were within the ASME Code, Class,2 emergency allowable limits, (Service Level C)

~

The structural i'ntegrity of the spiders was,verified by comparing the calculated plastic strain with the strain corresponding to the allowable stresses as defined in Paragraph F-134. 1.2 of Appendix F of,the ASME Code.

On the basis of analyses performed by the Shoreham applicant (Enclosures 6

and 7 of letter dated June 17,

1983, from Bechtel Power Corporation) that veri-fied the valve structural and pressure integrity and test results that demon-strated the valve operability and functionality, the staff finds that the design of the modified vacuum breaker valves for SSES is acceptable and can accommodate the effects of pool swell impact loadings following a design-basis LOCA.

The staff's conclusion is based on the analyses performed on the Shoreham valves, which have the same modifications as those at SSES except for the additional actuating cylinder on the SSES valve for damping of the maximum impact velocity.

,Thus, the SSES valves will experience lower impact velocities and corresponding lower loads than the,-Shoreham valves.

In a letter dated October 24, 1983, the applicant informed the staff that in-stallation of the modified vacuum breakers described above was completed for Susquehanna Unit 2.

Therefore, the staff finds this issue resolved for Susque-hanna Unit 2..

6.2.4 Containment Isolation Systems 6.2.4.3 Containment Pur e

S stem In Section l.10'f Supplement 5 to the SER, the staff provided a list of issues for which a condition was included, in the operating license for Susquehanna Unit 1 for which a similar license condition would be require'd for Unit 2 unless satisfactory resolution was reached on the issue before the licensing of Unit 2.

One such issue regarded the containment purge system.

The applicant had com-mitted to install debris screens on the drywell containment purge system during the first refueling outage.

Susquehanna SSER 6

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In a letter from N.

W. Curtis to A. Schwencer dated September 23, 1983, the applicant informed the staff that installation of debris screens on the drywell containment purge system for Unit 2 was complete.

The staff finds this issue for Unit 2 resolved.

6.6 Inservice Ins ection of Class 2, and 3

Com onents GDC 36, "Inspection of Emergency Core Cooling Systems";

39, "Inspection of Containment Heat Removal Systems";

42, "Inspection of Containment Atmosphere Cleanup Systems";

and 45, "Inspection of Cooling Water System," require,.in part, that the subject systems be designed to permit appropriate periodic inspection of important components to ensure system integrity and capability.

10 CFR 50.55a(g) defines the detailed requirements for the preservice and in-service inspection programs for light-water-cooled nuclear power facility com-ponents.

On the basis of a construction permit date of November 2, 1973, this section of the regulation requires that a PSI program be developed for Class 2

components and be implemented using at least the Edition and Addenda of Section XI of the ASME Code in effect 6 months before the date of issuance of

'he construction permit.

Also,'.the initial inservice inspection program must comply with the requirements of the latest Edition and Addenda of Section XI of the ASME Code in effect 12 months before the date of issuance of the operating

license, subject to the limitations and modifications listed in 10 CFR 50.55a(b).

6.6.3 Evaluation of Compliance With 10 CFR 50.55a(g) for Unit 2 The staff completed the review of the PSI Program for Unit 1 and determined that this document was acceptable as described in Section 6.6.2 of Supplements 3 and 4.

The preservice examination of Unit 2 was performed to the same ASME Code requirements (as modified by specific written relief requests) as the Unit 1 PSI Program.

Therefore, the staff has determined that the PSI Program for Unit 2 is acceptable on the basis of the staff review and acceptance of the corresponding document for Unit 1.

h The staff has completed the review of requests for relief from certain require-ments that the applicant determined to be impractical in letters dated August 2,

1983, November 1, 1983, and December 21, 1983, in which a supporting technical justification was provided.

The staff has determined that certain ASME Code,Section XI, examination requirements defined in 10 CFR 50.55a(g)(2) are imprac-tical.

Therefore, pursuant to 10 CFR 50.55a(a)(2),

the staff has allowed relief from the requirements that have been determined to be impractical and that if implemented would result in hardships or unusual difficulties without a compen-sating increase in the level of quality and safety.

On the basis of the grant-ing of relief from these preservice examination requirements, the staff con-cludes that the PSI Program for Unit 2 is in compliance with 10 CFR 50.55a(g)(2).

A detailed evaluation supporting this conclusion is provided in Appendix H to this report.

The initial inservice inspection program for Unit 2 will be eval-uated after the applicable ASME Code edition and addenda can be determined on the basis of 10 CFR 50.55a(b) and before the first refueling outage when in-service inspections will be performed.

Compliance with the inservice inspections required by Section XI of the ASME Code and 10 CFR 50 constitutes an acceptable basis for satisfying applicable inspection requirements of GDC 36, 39, 42, and 45.

Susquehanna SSER 6

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7 INSTRUMENTATION AND CONTROL 7.5 Safet -Related Dis la Instrumentation 7.5.2 Specific Findings Loss of Power to Instruments and Control S stems As a result of an event involving the loss of a significant amount of control room information at the Oconee plant, the staff issued IE Bulletin (IEB) 79-27.

The applicant was asked to review Susquehanna Unit 2 with respect to this bul-letin.

In response to this concern, the applicant initiated a detailed review and analysis of the Susquehanna Unit 2 power sources and submitted a response (letter from N.

M. Curtis to Director of Nuclear Reactor Regulation dated October 10, 1983).

In this response, the applicant stated that The power system distribution buses for all instrumentation and controls required to operate those systems used to achieve cold shutdown from full-power operation and the control room alarms and indications used by the operators to detect and diagnose the failure of these critical power supplies were identified.

Sufficient main control room alarms and indica-tions are available to (a) alert the operators to the loss of any critical instrument and control power supply and (b) allow for ready identification of the failed power bus.

Therefore, no design changes to instrument and control power supply availability displays were necessary.

(2)

The effect of the loss of individual instrument and control power supplies on shutdown system operator control and indication circuits have been iden-tified.

A tabulation of these effects will be used in preparing emergency procedures in accordance with the bulletin.

These procedures will be completed by fuel loading.

(3)

Susquehanna does not have Class lE inverters, and on the basis of review of IE Circular 79-02 and the non-Class lE inverter, design modifications and administrative controls are not required.

7'.3 Summary On the basis of its review of the applicant's design as discussed in the Final Safety Analysis Report (FSAR), the response to IEB 79-27, and the applicant's commitment to include in the Susquehanna Unit 2 emergency procedures the appro-priate operator actions requested by IEB 79-27, the staff considers this concern resolved.

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8 ELECTRIC POMER SYSTEMS PP8L proposed to modify the onsite distribution systems for Susquehanna Units 1 and 2 by letter dated September 26, 1983.

These modifications of the onsite distribution systems involve the installation of the two new engineered safe-guard transformers in addition to the two installed engineered safety features (ESF) transformers and retention of the construction substation off site after start of operation of Unit 2.

8.2 Offsite Power S stems The construction substation provided power for the initial plant construction and provides power for various auxiliary buildings around the plant during operation.

It is not interconnected with the plant auxiliary power system and the onsite distribution system.

The Susquehanna 230-kV yard tie line supplies power to the construction transformer through a motor-operated air break switch.

The construction transformer is protected by high-speed percentage differential, sudden pressure, and overcurrent relaying.

Direct tranfer trip facilities are used as the primary relaying scheme to open the circuit breakers at the remote terminals of the transmission line in the event of a transformer fault.

Backup protection is provided by a high-speed ground switch on the 230-kV side of the construction transformer.

The motor-operated air switch automatically opens after the 230-kV system is deenergized to isolate the construction transformer from the offsite transmission system and permit the reclosing of the transmis-sion line terminal circuit breakers to continue the supply of offsite power.

The staff has reviewed the construction substation system and concludes that the fault of the construction substation, including the transformer, will be isolated by the primary and backup protective relaying fast enough to supply offsite power to the onsite distribution systems without disruption.

Therefore, the construction substation connected to the offsite system is acceptable.

8.3 Onsite Emer enc Power S stems The ac onsite power system consists of four redundant and, independent

4. 16-kV ESF distribution systems with their 480-V load centers and motor control cen-

ters, 120-V vital ac power systems, and the standby power supplies (diesel gen-erator units).

Each 4. 16-kV ESF bus is normally connected to a preferred source

'hat is one of four engineered safeguard transformers connected respectively to the two 13. 8-kV startup

buses, two ESF transformers for each

13. 8-kV bus.

The staff had previously approved the onsite distribution system configuration in which one of the two ESF transformers supplied power to the two 4.16-kV ESF buses for Unit 1 operation.

The modification (adding two ESF transformers) doubles the capacity of the ESF transformers for the Susquehanna plant.

The capacity of the ESF transformers connected to the preferred source is sufficient to power the ESF loads of one unit and those loads required for concurrent safe shutdown of the second unit.

An analysis has shown that during load sequencing and operation, frequency and voltage are maintained at a level that would not degrade the performance of any load below minimum design requirements.

There-fore, this design modification of the onsite distribution systems is acceptable.

Susquehanna SSER 6

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W t

9 AUXILIARYSYSTEMS 9.1 Fuel Stora e and Handlin 9.1.4 Fuel Handling System

9. 1.4. 1 Heavy Loads As a result of'eneric Task A-36, "Control of Heavy Loads Near Spent Fuel,"

NUREG-0612,'Control of Heavy Loads at Nuclear Plants,"

was developed.

Follow-ing the issuance of NUREG-0612, a generic letter dated December 22, 1980, was sent to all operating plants, applicants for operating licenses, and holders of construction permits requesting that responses be prepared to indicate the degree of compliance with the guidelines of NUREG-0612.

The responses were to be made in two,stages.

The first response (Phase I) was to identify the load-shandling equipment within the scope of NUREG-0612 and to describe the associated general load-handling operations such as safe load paths, procedures, operator training, special and general purpose lifting devices, the maintenance,

testing, and repair of equipment, and the specifications for handling equipment.

The second response (Phase II),was intended to show that either single-failure-proof handling equipment was not needed or that single-failure-proof equipment had been provided.

This supplement contains the staff's evaluation of Phase I.

An evaluation of Phase II will be the subject of future correspondence.

By letter. dated December 22, 1980, PP&L was requested to review their provisions for handling and control of heavy loads at Susquehanna Unit 2 to determine the extent to which the guidelines of NUREG-0612 are currently satisfied and to discuss and commit to mutually agreeable changes and modifications'hat would be required in order to fully satisfy these guidelines.

f The staff and its consultant, EG8G Idaho, Inc.,

have reviewed the PAL submittal dated July 22, 1983, for Susquehanna Unit 2.

As a result of its review, EG8G has issued a Technical Evaluation Report (TER).

The staff has reviewed the TER and concurs with its findings that the guidelines in NUREG-0612, Section

5. 1. 1, have been satisfied.

The TER and the results of the NRC evaluation were pro-vided to the applicant in a letter from A. Schwencer to N. Curtis dated October 31, 1983.

The staff concludes that Phase I for Susquehanna Unit 2 is acceptable.

9.2. 1 Emergency Service Water System In Section

1. 10 of Supplement 5 to the SER, the staff provided a list of issues for which a condition was included in the operating license for Susquehanna Unit 1 for which a similar license condition would be required for Unit 2 unless satisfactory resolution was reached on the 'issue before licensing of Unit 2.

One such issue regarded single failure in the emergency service water system.

Susquehanna SSER 6

9-1

By letter dated November 8, 1982, PP&L described a single failure in the emer-gency service water (ESW) system that resulted in less than 100'eat removal capability from one ESM loop for a specific large-break los's-of-coolant accident (LOCA).

The scenario, described in detail below, results in two low-pressure core spray (LPCS) pumps being cooled by the operable ESW loop plus one'ow-pressure coolant injection (LPCI) pump (without cooling to the room, oil coolers, or seal cooler) t'o cool the core following the postulated LOCA.

General Electric performed analyses (reviewed and evaluated in Supplement 4 to the SER) to show that acceptable core cooling is maintained under these conditions if the single LPCI pump is operated for at least 10 min.

In that supplement, the staff also

. evaluated manufacturer's data for the LPCI pumps, backed up by test data that showed the LPCI pumps could operate for 10 min following loss of ESM.

As reported in Supplement 4, the, staff concluded that the analyses and pump tests were acceptable, and therefore, the design was acceptable.

In the November 8, 1982, letter, PP&L also identified several modifications that would eliminate a single active failure in the ESW system resulting from the above concern.

PP&L indicated that modifications would be made in the long term so that ESW cooling water would be available to the necessary emergency core cooling systems for all postulated single, failures in the ESW system.

By letter dated May 16, 1983, PP&L proposed a modification to the ESM system piping as a long-term resolution to the single-failure concern.

In the existing design the division 1 ESW loop (ESW pumps powered by diesel generators A and C) supplies water to LPCI pumps A and C; the division 2 ESM loop (powered by diesel generators B,and D) supplies cooling water to LPCI pumps B and D.

A loss of flow in the division 1 loop (same basic failure mode for division 2) causes loss of cooling to LPCI pumps A and C,

and the postulated LOCA can cause LPCI pumps B and D to be ineffective.

The most limiting single failure 'for the division 1 loop is the loss of diesel generator A, which causes loss of division 1 ESW loop flow (resulting from the failure to open of the bypass valve to the spray pond) and loss of LPCI pump A.

LPCI pump C would be available without cooling water.

The proposed modification is to repipe cooling water to LPCI pumps C and D so that cooling water will be provided by the opposite ESW loop.

Hence, the division 1 ESW loop would provide cooling water to LPCI pumps A and D, and the division 2 ESW loop would supply cooling water to LPCI pumps B and C..

With the proposed modifications at least one LPCI pump with cooling water would be avail-able for any postulated LOCA plus single active failure, including failure of a diesel generator to start.

It should be noted that the failure of either diesel generator C or D does not result in complete loss of flow in either ESW loop; therefore, only the LPCI pump powered by diesel generator C or D would be lost and cooling water would continue to be supplied to the r'emaining LPCI pumps (A, B, C, or D).

The proposed modifications enable the ESW system to transfer heat from the equipment important to safety under normal operating and accident'onditions assuming loss of offsite power and any single active failure in accordance with GDC 44, "Cooling Water."

On the basis of its review of the proposed modifications, the staff concludes that the ESW system meets the requirements of GDC 44 and that the proposed modi-fications resolve the concerns associated with a single failure in the ESW sys-tem resulting in less than 100X heat removal capability.

The staff, therefore, concludes the proposed modifications are acceptable.

Susquehanna SSER 6

9-2

The Susquehanna Unit 2 license will be'conditioned to require the completion of the design modifications to the ESM system before September 1, 1985.

9.2.3 Ultimate Heat Sink In Section 9.2.3 of the SER,'he staff accepted the utimate heat sink for single-unit operation because the applicant had used a less conservative method for determining decay heat loads than that in Branch Technical Position (BTP)

ASB 9-2.

In Section 2.4.4 of the SER, the staff required that, following spray pond efficiency tests, an analy'sis of.actual maximum temperature be performed using either 'BTP ASB 9-2 or "the American Nuclear Society (ANS) 5. 1 curve plus 10K to.estimate decay heat loads'.

The staff further required that if the tem-perature calculated in the new analysis is higher than the design maximum tem-'erature (95~F), Technical Specifications should include provisions for actions to be taken in accordance with Position C.4 of Regulatory Guide 1.27, i.e.,

lowering the power level of one unit if the initial 'pond temperature reaches a

certain value to be determined by analysis.

By letter dated December 21, 1983, the applicant provided the results of the spray pond efficiency test to justify two-unit operation.

The results of the spray pond test and the new, maximum temperature analysis showed that two-unit operation would be provided with sufficient cooling following a loss-of-coolant accident in one unit and a shutdown and cooldown of the remaining unit, if the spray pond operating temperature was limited to 81'F and the inventory was maintained at a minimum of 23 million gallons.

An evaluation of the test results can be found in Section 2.4.4 of this supplement.

As a result of'hese limitations, Technical Specifications will be modified to allow two-unit opera-tion when the pond temperature is equal to or less than 81 F and the water level at the overflow weir is equal to or greater than 678 ft 1 in.

mean sea level.

On the basis of its review of the applicant's analysis and Technical Specifica-tion limitations, the staff concludes that the ultimate heat sink will not exceed 95 F for two-unit operation.

It, therefore, concludes that the ulti-mate heat sink is acceptable for two-unit operation.

9.5 Fire Protection S stems 9.5.5 Alternate Shutdown Systems In Supplement 4 to the SER, the staff concluded that the fire protection for safe shutdown met staff guidelines.

By letter dated December 13, 1983, the applicant identified a recently discovered deviation to the staff's guidelines concerning the separation of the switchgear cooling equipment.

The Unit 2 emergency switchgear cooling system provides switchgear and load center cooling in the event of a loss of offsite power.

The load center and switchgear equipment is required for safe shutdown and must be kept at or below qualified temperatures.

The division I compressor motor and motor-operated valve are located within 9 ft of the division II compressor motor and motor-operated valve.

Providing a 1-hour wrap for the motors is not possible;

however, a 1-hour-rated bar rier is provided for cables and conduits associated with one division of the cooling system.

Automatic detection and sprinkler protection are provided in the area.

Susquehanna SSER 6

9"3

The in, situ combustible loading is negligible, and the possibili+y. for. the introduction of transient combustible materials is low because access is by means of a vertical ladder.

This combination of protection constitutes an adequate level of safety and is an acceptable deviation from the staff's guidelines.

9.5.8 Appendix R Statement On the basis of its evaluation, the staff concludes that with the following deviation, the fire protection program for Susquehanna Unit -1 and 2 will meet the technical requirements of Appendix R to 10 CFR 50 when the, committed modifications have been completed, meets the requirements of GDC 3, and, there-fore, is acceptable:

(1)

The separation provided for the switchgear cooling equipment, fire zone 2-5A, is acceptable without a 1-hour-rated fire barrier for the divisions I and II compressor motors and motor-operated valves.

Susquehanna SSER 6

13 CONDUCT OF OPERATIONS

13. 6 Industrial Securit 13.6. 1 Introduction The applicant has revised and amended the "Susquehanna Steam Electric Station Physical Security Plan" to comply with the requirements of 10 CFR 73.55 (see Appendix A for a listing of transmittal letters).

On the basis of its review of the subject documents and visits to the site, the staff has concluded that the protection provided by the applicant against radio-logical sabotage at Susquehanna meets the requirements of 10 CFR 73.

Accord-ingly, the protection ensures that the health and safety of the public will not be endangered.

The appendix to Section 13.6 of this SER supplement contains safeguards information and must be protected in accordance with the provisions of 10 CFR 73.21.

13. 6. 2 Physical Security Organization To satisfy the requirements of 10 CFR 73.55(b),,the applicant has provided a

physical security organization that includes a Security Shift Supervisor who is on site at all times with the authority to direct the physical protection activities.

To implement the commitments made in the physical security plan, the training and qualification plan, and the safeguards contingency plan, written security procedures specifying the duties of the security organization members have been developed and are available for inspection.

The training program and critical security tasks and duties for the security organization personnel are defined in the "Susquehanna Security Training and qualification Plan," which meets the requirements of 10 CFR 73, Appendix 8, for the training, equipping, and requalification of the security organization members.

The physical security plan and the training program provide commitments that pre-clude the assignment of any individual to a security-related duty or task before the individual is trained,

equipped, and qualified to perform the assigned duty in accordance with the approved guard training and qualification plan.

13.6.3 Physical Barriers To meet the requirements of 10 CFR 73.55(c),

the applicant has provided a pro-tected area barrier that meets the definition in 10 CFR 73.2(f)(l).

An isola-tion zone, to permit observation of activities along the barrier, of at least 20 ft is provided on both sides of the barrier with the exception of the loca-tions listed in the protected appendix.

The staff has reviewed those locations and determined that the security measures in place are satisfactory and continue to meet the requirements of 10 CFR 73.55(c)

~

Illumination of 0.2 ft-candle is maintained for the isolation zones, protected area barrier, and external portions of the protected area.

Susquehanna SSER 6

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13.6.4 Identification of Vital Areas The design basis for the applicant's program for identifying vital equipment included the regulatory definition of vital in 10 CFR 73. 2(h)(i), 10 CFR 100 release limits, and the criteria contained in Regulatory Guide 1.29 and Review Guideline 017, "Definition of Vital Areas," Revision 2.

The protected appendix contains a discussion of the applicant's program and identifies those areas and equipments determined to be vital.

Vital equipment is located within vital areas that are located within the pro-tected area and that require passage through at least two barriers, as defined in 10 CFR 73.2(f)(1) and (2), to gain access to the vital equipment.

Vital area barriers are separated from the protected area barrier.

The control room and central alarm station are provided with bullet-resistant walls, doors, ceilings, floors, and windows.

On the basis of these findings and the analysis set forth in Paragraph C of the protected

appendix, the. staff has concluded that the applicant's program for identification and protection of vital equipment satisfies the regulatory intent.

However, this program is subject to onsite validation by the staff in the future and to subsequent changes if they are found to be necessary.

13.6.5 Access Requirements In accordance with 10 CFR 73.55(d), all points of personnel and vehicle access to the protected area are controlled.

The individual responsible for control-ling the final point of access into the protected area is located in a bullet-resistant structure.

As part of the access control program, vehicles (except under emergency conditions), personnel,

packages, and materials entering the protected area are searched for explosives,

firearms, and incendiary devices by electronic search equipment and/or physical search.

Vehicles admitted to the protected

area, except applicant-designated

vehicles, are controlled by escorts.

Applicant-designated vehicles are limited to onsite station functions and remain in the protected area except for operational main-

tenance, repair, security, and emergency purposes.

Positive control-over the vehicles is maintained by personnel authorized to use the vehicles or by the escort personnel.

A picture badge/key card system, using encoded information, identifies individ-uals who are authorized unescorted access to protected and vital areas and is used to control access to these areas.

Individuals not authorized unescorted access are issued non-picture badges that indicate an escort is required.

Access authorizations are limited to those individuals who need access to perform their duties.

Unoccupied vital areas are locked and alarmed.

During periods of refuel-ing or major maintenance, access to the reactor containment(s) is positively controlled by a member of the security organization to ensure that only authorized individ-uals and materials are permitted to enter.

In addition, all doors and personnel/

equipment hatches into the reactor containment(s) are locked and alarmed.

Keys, locks, combinations, and related equipment are changed on an annual basis.

In Susquehanna SSER 6

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addition, when an individual s access authorization has been terminated because of a lack, of reliability or trustworthiness, or poor work performance, the keys, locks, combinations, and related equipment to which that person had access are changed.

tc 13.6.6 Detection Aids To satisfy the requirements of 10 CFR 73.55(e),

the applicant has installed intrusion detection systems at the protected area barrier, at entrances to vital areas, and at all emergency exits.

Alarms from the intrusion detection system annunciate within the continuously manned central alarm station and a

secondary alarm station located within the protected area.

The central alarm station is located so that the interior of the station is not visible from out-side the perimeter of the protected area.

In addition, the central station is constructed so that walls, floors, ceilings, doors, and windows are bullet resistant.

The alarm stations are located and designed in such a manner that a single act cannot interdict the capability of calling for assistance or responding to alarms.

No functions or duties that would interfere with its alarm response function are performed in the central alarm station.

The intru-sion detection system transmission lines and associated alarm annunciation hardware are self checking and tamper indicating.

Alarm annunciators indicate the type of alarm and its location when activated.

An automatic indication of when the alarm system is on standby power is provided in the central alarm station.

13.6.7 Communications As required in 10 CFR 73.55(f), the applicant has provided for the capability of continuous communications between the central and secondary alarm station operators,

guards, watchmen, and armed response personnel through the use of a conventional telephone system and a security radio system.

In addition, direct communication with the local law enforcement authorities is maintained through the use of a conventional telephone system and two-way FM radio links.

All nonportable communication links, except the conventional telephone

system, are provided with an uninterruptible emergency power source.

13. 6. 8 Test and Maintenance Requirements To meet the requirements of 10 CFR 73.55(g),

the applicant has established a

program for the testing and maintenance of all intrusion alarms, emergency

alarms, communication equipment, physical barriers, and other security-related devices and equipment.

Equipment or devices that do not meet the design per-formance,criteria or that have failed to operate will be compensated for by appropriate measures as defined in the "Susquehanna Steam Electric Station Physical Security Plan" and onsite procedures.

The compensatory measures will ensure that the effectiveness of the security system is not reduced by failures or other contingencies affecting the operation of the security-related equip-ment or structures.

Intrusion detection systems are tested for proper perform-ance at the beginning and end of any period during which they are used for security.

Such testing will be conducted at least once every 7 days.

Systems for onsite communication are tested at the beginning of each security shift.

Offsite communication systems are tested at least once each day.

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Audits of the security program are conducted once every 12 months by personnel who are independent of site security management and supervision.

The audits, focusing on the effectiveness of the physical protection provided by the onsite security organization implementing the approved security program plans,

include, but are not limited to, a review of the security procedures and practices, sys-tem testing and maintenance

programs, and local law enforcement assistance agreements.

A report is prepared documenting audit findings and recommenda-tions and is submitted to the plant management.

13.6.9

Response

Requirements To meet the requirements of 10 CFR 73. 55(h), the applicant has provided for armed responders immediately available for response duties on all shifts con-sistent with the requirements of the regulations.

Considerations used in support of this number are contained in the protected appendix.

In addition, liaison with local law enforcement authorities to provide additional response support in the event of security events has been established and documented.

The applicant's safeguards contingency plan for dealing with thefts, threats, and radiological sabotage satisfies the requirements of 10 CFR 73, Appendix C.

The plan identifies security events that could initiate radiological sabotage and identifies the applicant's preplanning, response resources, safeguards contingency participants, and coordination activities for each identified event.

Through this plan, upon the detection of abnormal presence or activities within the protected or vital areas, response activities using the available resources would be initiated.

The response activities and objectives include the neutral-ization of the existing threat by requiring the response force members to interpose themselves between the adversary and his objective, instructions to use force commensurate with that used by the adversary, and authority to request sufficient assistance from the local law enforcement authorities to maintain control over the situation.

To assist in the assessment/response activities, a closed circuit television

system, providing the capability to observe the entire protected area perimeter, isolation zones, and most of the protected

area, is provided to the security organization.

l3.6. 10 Employee Screening Program To meet the requirements of 10 CFR 73.55(a) to protect against the design-basis threat as stated in 10 CFR 73. 1(a)(1)(ii), the applicant has provided an em-ployee screening program.

Personnel who successfully complete the employee screening program or its equivalent may be granted unescorted access to pro-.

tected and vital areas at the Susquehanna site.

All other personnel requiring access to the site are escorted by persons authorized and trained for escort duties who have successfully completed the employee screening program.

The employee screening program is based on accepted industry standards and includes a background investigation, a psychological evaluation, and a continuing obser-vation program.

In addition, the applicant may recognize the screening programs of other nuclear utilities or contractors on the basis of a comparability review conducted by PP8 L.

The plan also provides for a "grandfather clause" exclusion, which allows recognition of a certain period of trustworthy service with the Susquehanna SSER 6

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utility or contractor a's being equivalent to the overall employee screening program.

THe staff has reviewed the applicant's screening program against the accepted industry standard (ANSI N18. 17-1973) and has determined that the program is acceptable.

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14 INITIALTEST PROGRAM In letters from N.

W. Curtis to A. Schwencer dated October 13,

1983, and December 29, 1983, PP8L forwarded revisions to Chapter 14 of the Susquehanna FSAR.

The revisions add Sections 14.2.12.4, 14.2.12.5, and 14.2.12.6 to provide separate test descriptions for Unit 2 preoperational, acceptance, and startup tests.

FSAR Sections 14.2.12.1, 14.2.12.2, and 14.2.12.3, which originally applied to both units, are retained as descriptions of Unit 1 tests.

Since the Unit 1 startup has been successfully completed, the staff's review was limited to the new test descriptions for Unit 2 contained in Sections

14. 2 ~ 12. 4,

14. 2. 12. 5, and 14. 2. 12. 6.

The Unit 2 test descriptions do not include some tests that are included for Unit 1.

These are tests of shared or identical systems for which all Unit 1 and Unit 2 test objectives were accomplished during the Unit 1 test program.

Also, the test descriptions include some tests that were not included for Unit 1.

They are descriptions of tests for systems, structures, and equipment unique to Unit 2 or which were not provided for Unit 1 before its licensing.

These differences are described in a letter from N.

W. Curtis to A. Schwencer dated December 21, 1983.

The objective of this review was to determine if the new Unit 2 test descrip-tions describe an initial test program that is as comprehensive as that of the previously evaluated and accepted Unit 1 test program.

The staff's review included verification of the following items:

(1)

There are test descriptions for those Unit 2 structures,

systems, compo-

nents, and design features that (a) will be used for shutdown and cooldown of the reactor under normal, transient, and accident conditions and for maintaining the reactor in a safe shutdown condition for an extended period of time; (b) will be used for establishing conformance with safety limits or limiting conditions for operation that will be included in the facility Technical Specifications; (c) are classified as engineered safety features or will be relied on to support or ensure the operations of engineered safety features within design limits; (d) are assumed to func-tion or for which credit is taken in the accident analysis of the facility, as described in the FSAR; or (e) will be used to process, store, control, or limit the release of radioactive materials.

(2)

The test objectives, prerequisites, test methods, and acceptance criteria for each Unit 2 test description include sufficient detail to establish that the functional adequacy of the structures,

systems, components, and design features will be demonstrated.

On the basis of this review and its previous evaluation, the staff has concluded that the Unit 2 initial test program is acceptable and meets the requirements of 10 CFR 50.34(b)(6)(iii), which requires inclusion of plans for preoperational testing and initial operations in the

FSAR, and 10 CFR 50, Appendix B, Section XI, which requires a test program to ensure that all testing required to demonstrate that structures,

systems, and components will perform satisfactorily in service Susquehanna SSER 6

14" 1

is identified and performed in accordance with written test procedures that in-corporate the requirements and acceptance limits contained in applicable design documents.

The staff has further concluded that the initial test program described in the application meets the acceptance criteria of SRP Section 14.2 (NUREG-0800),

and the successful completion of the test program will demonstrate the functional adequacy of Unit 2 structures,

systems, and components.

Because the holder of an operating license has the legal option to make changes to the initial test program pursuant to 10 CFR 50.59, the staff will condition the Unit 2 operating license, similarly to that of Unit 1, to require the appli-cant to complete the initial startup test program described in the FSAR without making any major modifications unless such modifications have prior NRC approval.

Major modifications will be defined in the license as (1)

Elimination of any test described in FSAR Chapter 14 and not identified therein as being nonessential (2)

Modification of objectives,

methods, or acceptance criteria for any test described in FSAR Chapter 14 and not identified therein as being non-essential (3)

Performance of any test not identified as nonessential at a power level different from that stated in the FSAR by more than 5X of rated power (4)

Failure to satisfactorily complete any test not identified as nonessential (5)

Failure to satisfactorily complete the entire initial startup test pro-gram by the time core burnup equals 120 effective full-power days (6)

Deviation from initial test program administrative procedures or initial test program quality assurance controls described in the FSAR (Chapters 13, 14, and 17)

(7)

Delays in excess of 30 additional days (14 additional days if power level exceeds 50Fo) between any two successive milestones depicted in the startup test schedule in the FSAR. If continued power operation for purposes

'other than testing is desired during such a delay, the licensee shall submit a safety analysis to show that adequate testing has been performed and evaluated to demonstrate that the facility can be operated without increased risk to public safety.

Susquehanna SSER 6

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17 EQUALITY ASSURANCE 17.6 Confirmator In-De th Review Pro ram In Section l. 10 of Supplement 5 to the SER, the staff provided a list of issues for which a condition was included in the operating license for Susquehanna Unit 1 for which a similar license condition would be required for Unit 2 unless satisfactory resolution was reached on the issue before licensing of Unit 2.

One such issue regarded the assurance of proper design and construction.

In a letter dated March 16,

1983, the applicant provided the staff with a sum-mary of recent audits and reviews conducted on Susquehanna Unit 2 activities as a means of confirming Unit 2 design adequacy.

In addition, PP8 L provided in a letter dated April 7, l983, a copy of the self-initiated evaluation of the Susquehanna Unit 2 construction project using Institute of Nuclear Power Opera-tions Performance Objectives and Criteria for Project Evaluations.

The staff reviewed these submittals and determined that a separate independent design verification process (IDVP) is not required on Unit 2 because the design process of Unit 2 is essentially the same as that applied to Unit 1 and incorpo-rates improvements made as a result of lessons learned on the Unit 1 IDVP.

The staff finds this issue resolved for Unit 2.

Susquehanna SSER 6

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22 TMI-2 RE(UIREMENTS 22.2 TMI Action Plan Re uirements for A licants for 0 eratin Licenses I

0 erational Safet I.D. 1 Control Room Desi n Review In Section

1. 10 of Supplement 5 to the SER, the staff provided a list of issues for which a condition was included in the operating license for Susquehanna Unit 1 for which a similar license condition would be required for Unit 2 unless satisfactory resolution was reached on the issue for licensing Unit 2.

One such issue regarded the display control system report discussing the experience, i'ncluding demonstrated reliability, of the system.

Because SSES uses a common control room design for Units 1 and 2, and the multi-ple cathode ray tube display design is essentially identical for each unit, the staff will require only a single report from the applicant on the experience and reliability of the display control system for use in making future decisions.

Therefore, the staff concludes the license condition contained in the Unit 1 license is sufficient for'current staff needs and a similar condition in the Unit 2 license is not required.

The applicant's preliminary 'design assessment (PDA) and the staff's audit of the Susquehanna Unit 1 control room identified 42 human engineering djscrepan-cies (HEDs) that required correction before licensing.

On July 17, 1982, Unit 1 received a license for low-power operation on the bsais of the applicant's cor-rection of most of these HEDs.

Correction of the remaining HEDs was completed, in accordance with the license condition, by September 1, 1982.

Supplement 3

noted that the Susquehanna Unit 2 control room must be subjected to either a

PDA or a detailed control room design review (DCRDR) before licensing of that unit.

To satisfy that requirement, the applicant verbally committed to incor-porate all HED corrections applied to the Unit 1 control room into the design for the Unit 2 control room.

Supplement 5 noted that the applicant should pro-vide a written commitment to this effect.

This commitment was subsequently received by the staff.

In addition, Supplement 5 noted that if the applicant expects licensing, of Unit 2 to be based on the PDA for Unit 1, any differences between the two control rooms must be determined and addressed in a supplement

, to the Unit 1 PDA.

Supplement 5 also noted that corrections of HEDs in the Unit 2 control room based on the applicant's PDA for Unit 1 should be completed before licensing.

In addition, the applicant should submit a report addressing all HEDs at least 6 months before licensing to ensure timely closeout of the prelicensing control room design review.

The report should list proposed corrective actions for the HEDs, implementation schedules, and any deviations from previous commitments.

Justifications for deviations from previous commitments should also be provided.

The staff will require written confirmation before licensing that the Unit 1 HED corrections have been incorporated in the Unit 2 control room.

It will Susquehanna SSER 6

22-1

require a report before licensing, describing any differences betWeen the Unit 1 and Unit 2 control rooms and addressing any HEDs resulting 'from these differ-ences.

The staff will also require as a condition of the Unit 2 license that all Unit 1 HEDs requiring correction as a result of the 'applicant's DCRDR be corrected in the Unit 2 control room.

PP&L will be required to submit, for review and approval by the NRC staff, the schedule for implementing all HED corrective actions resulting from the DCRDR by March 1, 1985.

I.G. 1 Trainin Durin Low-Power Testin In Supplement 1 the staff stated that it would review the applicant's safety analysis and test procedures for a simulated loss of onsite and offsite ac power test (station blackout or SBO test).

This test was to be performed sub-ject to a safety analysis finding that the test would not constitute a risk to public safety or a risk of damage to plant equipment.

In Supplement 3 the staff stated that an analysis had been received from the applicant, but that it con-tained insufficient information.

In a letter dated August 25, 1982, the appli-cant forwarded additional information.

The staff evaluated the information and concluded, as reported in Generic Letter 83-24 dated June 29, 1983, that the SBO test is not warranted in view of the possibility of damage to plant equipment.

This generic letter further stated that compliance with the BWR Owners Group recommendations in a letter dated February 4, 1981, constitutes an acceptable Item I.G. 1 program.

In a letter dated August 19; 1983, the applicant reaffirmed his commitment to the BWR Owners Group recommendations.

On the basis of the applicant's commitment to the BWR Owners Group program and consistent with its position in the generic letter, the staff concludes that the applicant's program meets the requirements of Item I.G. l.

II Sitin and Desi n

II. E

System Design

II.E. 4. 2 Containment Isolation De endabilit In Section

1. 10 of Supplement 5 to the SER, the staff provided a list of issues for which a condition was included in the operating license for Susquehanna Unit 1 for which a similar license condition would be required for Unit 2 unless satisfactory resolution was reached on the issue before licensing of Unit 2.

One such issue regarded the operability of containment purge and vent valves.

Re uirements Demonstration of operability of the containment purge and vent valves, particu-larly the ability ; f these valves to close during a design-basis

accident, is necessary to ensu: e containment isolation.

This demonstration of operability is required by Branch Technical Position CSB 6-4 and SRP Section

3. 10 (NUREG-0800) for containment purge and vent valves that are not sealed closed during opera-tional conditions 1, 2, 3, and 4.

Susquehanna SSER 6

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Descri tion 'of Pur e and Vent Valves The valves identified as the containment isolation valves in the purge and vent system in which operability has not previously been demonstrated are:

Valve P8 ID number HV-1,2 25703 HV-1,2 25704 HV-1,2 25724 HV-1,2 25725 HV-1,2 25713 HV-1,2 25714 HV-1,2 25722 HV-1,2 25723 Valve size 18 18 18 18 24 24 Butte fly Butterfly Butterfly Butterfly Butterfly Butterfly Butterfly Butterfly Location Outside containment Outside containment Outside containment Outside containment Outside containment Outside containment Outside containment Outside containment The 18-and 24-in. valves are H. Pratt valves Model 1200, 150 lb, with an offset asymmetric disc.

The 18-in. valves are equipped with Bettis Operators, Model T312-SR3, air open-spring close.

The 24-in. valves are equipped with Bettis Operators, Model T416-SR3.

PP8 L's assessment is that the valves are capable of closing from the full-open,(90 ) position under the accident case postulated.

PP8 L has previously demonstrated operability of the 6-in. valves installed in the purge vent system.

Demonstration of 0 erabi lit PP8L has provided information in a letter dated April 13, 1983, demonstrating operability of the purge and vent system isolation valves for SSES units in the following submittals:

(1)

H. Pratt qualification Analysis Report for the 18-in. valves HBB-BF-A0-5703,

5704, 5724, and 5725 dated January ll, 1983 (2)

H. Pratt qualification Analysis Report for the 24-in. valves HBB-BF-A0-5713,

5714, 5722, and 5723 dated January 28, 1983 PP8 L's approach to operability demonstration is based on the following considerations:

(1)

The maximum dynamic torque occurs when initial sonic flow occurs.

This corresponds with an open angle of 68 for an asymmetric disc.

(2)

Closure plus delay time equalled ll sec.

Susquehanna SSER 6

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(3)

Closure time under LOCA conditions is less than no-load stroke times.

(4)

Flow direction through the valve is toward the hub side (asymmetric disc),

which is the worst-case dynamic torque developed.

(5)

Single valve closure is assumed.

(6)

(7)

All valves are air operated and are located outside containment.

Contain-ment back-pressure effect is not applicable.

'I Accumulators are not part of any valve assembly.

(8)

The analysis of the structural integrity and operational adequacy of the valve assembly is based principally on containment pressure versus time

data, system response (delay) time, piping geometry upstrea'm of the valve, back pressure resulting from ventilation components downstream of the valve, valve orientation, and direction of valve closure.

Evaluation Revised pressure response and temperature response curves for a recirculation line break are presented.

A peak wetwell pressure of 41 psia and a peak dry-well pressure of 58.2 psia were used in the analysis.

FSAR Section 6.2. 1. 1.3. 1 states that the calculated accident parameter is 43.8 psig and 29 psig for the drywell and suppression

chamber, respectively.

The staff bases its review on the latest submittal or the 41 psia and 58.2 psia values.

The analysis presented states that the maximum dynamic torque occurs when initial sonic flow occurs.

This corresponds with an open angle of 68 for an asymmetric disc.

Downstream pressure was selected by considering the valve closure time and pressure time curves

'so that the downstream pressure at 68 would yield the critical ratio for the air/stream mixture.

This was considered by H. Pratt and the staff, on the basis of the information submitted, to be the worst-case approach in determining valve loading.

H. Pratt's approach to determining dyamic torque TD for the subject valves is

based, in part, on the fact that H. Pratt has determined from the model valve tests that the maximum value of TD occurs when initial sonic flow oc'curs coinci-dent with a disc angle of 68 for the asymmetric disc (90

= full open).

On the basis of this, the TD equation for sonic flow (given in the submittal) is used with appropriate dynamic torque coefficient, media difference (steam/air mix-ture),

and size difference factors to determine the maximum value of TD possible in the subject valves.

Coefficient of friction used for the bronze bearings is 0.25.

Seating torques (T ) are calculated by an equation in American Water Works Association (AWWA) C504-80.

Seating factor or coefficient of seating (CS) is said to be determined by Pratt laboratory tests.

Susquehanna SSER 6

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T defined as "maximum operating torque for valve" is used in the applicable 8

areas of the stress analysis as the torque load.

T8 "is shown to be the higher value of the algebraically combined TD and TB or TB plus TS.

For the 18.0-in.

valves, T8 is 20,551 in.-lb or basically equal to TD, which is more conservative than T

- T For the 24.0-in. valves, T

is 69,617 in.-lb or basically equal to TD, which again is more conservative than 'TD - TB, to which the staff agrees.

In the analysis reports, H. Pratt has indicated that the stress analysis is structured to comply with Paragraph NB-3550 of Section III'of the ASME Code and that design rules for Class 1 valves are used (exceed rules for Classes 2 and 3).

H. Pratt states that valve components are analyzed under the assumption that the valve is either at maximum fluid dynamic torque or seating against the maximum design pressure.

An analysis temperature of 300oF is used along with 5g seismic accelerations statically applied simultaneously in each of three mutually per-pendicular directions.

Stress summary tables were provided for both the 18-and 24-in. isolation valves.

As requested by the

NRC, H. Pratt has revised the allowable shear stress to 0.4Sy.

Using the revised peak post-LOCA wetwell pressure in combination with the allowable shear stress of 0.4Sy and with the addition of new materials in the top disc pin and redesign of the bonnet for the 24-in. valve, the stress levels for the 18-and 24-in. valves were found to be below the Code allowable values and acceptable.

Closing time, including delay time, is said to be ll sec.

However, this is not an issue because the analysis has considered a constant peak containment pressure throughout the analysis.

In the submittal dated April 13,

1983, PP&L committed to make the modifications to the 24-in. valves before startup following the first refueling outage for Unit 1.

For Unit 2, the modif'ication will be made before fuel loading.

This schedule is acceptable to the staff.

~Summar The staff has completed its review of the information submitted to date concerning operability of 18-and 24-in. containment purge and vent valves for the Susque-hanna Steam Electric Station.

The staff finds the information submitted demon-trates the ability of the 18-and 24-in.

purge and vent valves to close against the buildup of containment pressure in the event of a LOCA.

The staff considers this issue resolved.

II.F;2 Instrumentation for Detection of Inade uate Core Coolin Supplement 4 to the SER indicated that PP&L was expected to submit a report by August 31, 1982, addressing the analyses performed by the BWR Owners Group re-garding additional instrumentation relative to inadequate core cooling and that PP&L would be requested to implement the staff's requirements after the comple-tion of the staff's review of this report.

Accordingly, the Susquehanna Unit 1 license was conditioned on the submittal of this report.

Susquehanna SSER 6

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In response to the license condition, PP8L submitted a report by letter of August 31,

1982, from N.

W. Curtis (PAL) to A. Schwencer (NRC).

This submittal addressed the analyses in BWR Owners Group report, SLI-8211, "Review of BWR Reactor Water Level Measurement Systems,"

and BWR Owners Group report, SLI-8218, "Inadequate Core Cooling Detection in BWRs."

The staff has not developed a final position on inadequate core cooling instru-ment requirements'.

Any additional requirements stemming from the staff's re-view of the inadequate core cooling instrumentation will be imposed following the development of a final position.

The operating license for Susquehanna Unit 2 will be conditioned to require PAL to implement such additional require-ments, if any.

II.K.3 Final Recomendations of Bulletins and Orders Task Force.

II.K.3. 18 Modification of Automatic De ressurization S stem Lo ic-Feasibi lit for Increased Diversit for Some Event Se uences The automatic depressurization system (ADS), through selected safety relief

valves, functions as a backup to the operation of the high-pressure coolant systems.

The ADS depressurizes the vessel so that low-pressure systems may in-ject water into the reactor vessel.

The ADS is typically activated automatically on receipt of coincident signals of low water level in the reactor vessel, high drywell pressure, and the running of any low-pressure emergency core cooling system pump.

A time delay of approximately 2 min after receipt of the coinci-ent signals allows time for the automatic blowdown to be bypassed manually if the operator believes the signals are erroneous or if the water level can be restored.

for transient and accident events that do not directly produce a high drywell pressure signal (e.g.,

stuck-open relief valve or steamline break outside con-tainment) and are degraded by a loss of high-pressure coolant systems, manual actuation of the ADS is required to provide adequate core cooling.

A reliabil-ity and risk assessment was requested so that the optimum approach to eliminate the need for manual actuation could be obtained.

A further consideration is that proposed modifications to the ADS logic should be such that operator actions that may be required during an anticipated transient without scram (ATWS) would not be complicated by the ADS.

The BWR Owners Group response provided in a letter to D.

G ~ Eisenhut (NRC) from T. J.

Dente (BWR Owners Group)

(BWROG-8260) dated October 28, 1982, did not pro-vide the requested reliability and risk assessment.

It did provide a discussion of the advantages and disadvantages of each of several options.

A qualitative discussion of the risk and reliability was provided.

Eight ADS logic options are considered in the BWR Owners Group response:

the current design and seven logic modifications.

The seven modifications are (2) elimination of the high drywell pressure permissive with the addition of a manual switch to inhibit automatic depressurization elimination of the high drywell pressure permissive and changing the low reactor pressure vessel (RPV) level trip setpoint to the top of the active fuel (TAF)

Susquehanna SSER 6

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(3) addition of a manual switch to inhibit automatic blowdown in conjunction with a timer that bypasses the high drywell pressure permissive if the reactor water level is low for a sustained period

'4) addition of a timer that bypasses the high drywell pressure permissive if the reactor water level is low for a sus'tained period and changing the low RPV water level trip setpoint to the TAF (5) addition of a manual switch to inhibit automatic blowdown in conjunction with a suppression pool temperature permissive in parallel with the high drywell pressure permissive (6) addition of a suppression pool temperature permissive in parallel with the high drywell pressure permissive and changing the low RPV water level trip setpoint to the TAF (7) 'addition of a manual switch to inhibit automatic blowdown As 'indicated initially in the staff position, the present ADS logic design (except for-those few plants that do not have the high drywell pressure per-missive) does not satisfy the requirement to eliminate the need for operator action because it has not been demonstrated that the high drywell pressure signal would be present for all situations requiring ADS actuation.

The second option, elimination of the high drywell pressure permissive and addi-tion of a manual inhibit switch, satisfies the requirement and is simple to implement.

further, the manual inhibit switch permits the operator to override the automatic blowdown logic if necessary.

Therefore, the second option is acceptable.

The third option, elimination of the high drywell pressure permissive and changing the low RPV water level trip setpoint to the TAF, satisfies the re-quirement to eliminate the need for manual action to blow down the vessel but could require repeated operator action (approximately e0ery 2 min) to reset the ADS timer for ATWS events where low water level is deliberately maintained to reduce power.

Changing the low level trip setpoint may also be very expensive because installation of new water level instrumentation would be required for many plants.

This option was, therefore, not recommended by the BWR Owners Group.

The fourth option, addition of a timer that bypasses the high drywell pressure permissive if the reactor water level is low for a sustained period and addition of a manual inhibit switch, also satisfies the requirement and is simple to implement.

The time delay used must be justified by analysis if this option is chosen, and the Technical Specifications must be modified to require testing of the timer.

The fourth option is acceptable to the staff.

The f)fth option, addition of a timer that bypasses the high drywell pressure permissive if the reactor water level is low for a sustained period and changing the low RPV water level trip setpoint, was not recommended for the same reasons as those discussed for the third option.

The sixth option, addition of a suppression pool temperature permissive in parallel with the high drywell pressure permissive and a manual inhibit switch, Susquehanna SSER 6

22-7

would theoretically satisfy the requirements.

However, temperature variations within the suppression pool would necessitate the use of many thevmocouples connected through averaging circuits.

This option was rejected by the 8WR Owners Group because it is relatively impractical.

The seventh option, addition of a suppression pool temperature trip in parallel with the high drywell pressure trip and changing the low RPV water level trip setpoint to the TAF, was rejected by the BWR Owners Group for the same reason as that given for the sixth option.

The eighth option, addition of a manual inhibit switch, does not satisfy the requirement because manual action would still be required for breaks that do not pressurize the drywell.

The second, third, fourth, and fifth options effectively remove the high dry-well pressure permissive for ADS actuation.

Addition of the manual inhibit switch (options 2, 4, and 8) enables the operator to override the ADS should this be necessary (as for some ATWS events).

Suppression pool temperature permissives are judged to be impractical.

Changes to the RPV low water level trip setpoint may not be sufficient to provide the operator with the flexibil-ity needed to override the ADS when needed.

It was concluded, therefore, that two of the eight options proposed are accept-able.

They are option 2, elimination of the high drywell permissive and the addition of a manual inhibit switch, and option 4, bypass of the high drywell pressure permissive after sustained low water level and the addition of a manual inhibit switch.

By letter dated October 1, 1982 (PLA-1312),

PP8L adopted the results of the BWR Owners Group study on TNI Action Plan Item II.K.3. 18.

The applicant has com-mitted to modify the ADS logic to bypass the high drywell pressure trip after a

sustained low water level signal, and to add. a manual switch that may be used to inhibit ADS actuation if necessary.

This is consistent with option 4 of the BWR Owners Group study and is acceptable to the staff with the following conditions:

(1)

Installation at Unit 1 must be completed before startup following the first refueling outage; installation at Unit 2 must be completed before initial criticality.

(2)

Technical Specifications must be provided for the bypass timer and manual inhibit switch.

(3)

The use of the inhibit switch must be addressed in the plant emergency procedures.

(4)

A plant-specific analysis must be provided to justify the bypass timer setting.

In a letter dated July 7, 1983, PAL provided the results of analyses to deter-mine the setting for the ADS high drywell pressure permissive bypass timer.

The timer setting was determined by consideration of LOCAs, loss of inventory

events, and ATWS events.

The analyses were initially performed using realistic models and inputs in order to establish a range of possible settings.

PP&L Susquehanna SSER 6.

22-8

then selected a 480-sec setting and performed LOCA and loss-of-inventory-event calculations using approved Appendix K models.

The peak cladding temperature (PCT) for the worst-case event with a timer setting of 480 sec was calculated to be 1500 F.

This is below the PCT limit of 2200'F The staff has reviewed the applicant's proposed setting for the ADS bypass timer and the results of his supporting analysis.

The staff concludes that the proposed timer setting of 480 sec is acceptable.

In a letter dated February 22,

1984, from N.

W. Curtis to the Director,

NRR, PPEL requested a change to conditions of the applicant's response to TMI Action Plan Item II.K. 3. 18.

The applicant has requested that the completion date for plant emergency procedures and Technical Specifications related to the manual inhibit switch for the ADS be delayed for Unit 2 to be concurrent with the first refueling outage for Unit l.

The staff has reviewed the applicant's submittal and the current requirements for TMI Action Plan Item II.K.3. 18 for Susquehanna Units 1 and 2.

The staff notes that the currently required implementation schedules are different for Units 1 and 2 for both hardware installation and for preparation of procedures and Technical Specifications.

This was based on the different construction schedules for the two units and equipment availability.

The staff also notes that operators at Susquehanna are normally qualified on both Units 1 and 2.

Implementation of the current requirements would therefore dictate the training of the same operators on different sets of equipment and to differing procedure's for the two units.

The staff considers this to be undesirable.

Furthermore, the staff has considered the intended function of the manual inhibit switch, which is to allow the operator to prevent automatic ADS initiation under cer-tain ATWS conditions.

It is the staff's judgment that the likelihood of. an ATWS event requiring the use of the manual inhibit switch in the time period of the proposed delay is small.

Therefore, because of the potential complication in operator training and the low likelihood of the ATWS event, the staff con-cludes that the implementation delay proposed by the applicant is acceptable.

During the interim period, the manual inhibit switch, which is already installed, should be disabled because there are no procedures for its use.

The following condition will be included in the license for Susquehanna Unit 2:

(1)

Prior to achieving initial criticality, PP8L shall:

(i)

Install modifications to the Automatic Depressurization System acceptable to the NRC, and (ii)

Propose Technical Specifications for the bypass timer setting and surveillance requirements for the bypass timer.

(2)

Prior to September 1, 1985, PP8L shall:

(i)

Incorporate into the Plant Emergency Procedures the usage of the manual inhibit switch, and (ii)

Propose Technical Specifications for the manual inhibit switch.

Susquehanna SSER 6

22-9

(3)

PP8L shall maintain the manual inhibit switch disabled until License Condition (2) above is satisfied.

II.K.3.25 Effect of Loss of Power on Alternatin Current Pum Seals In Supplement 1 to the SER, the staff indicated the Unit 1 operating license would be conditioned to require, by first refueling, that the applicant provide an emergency power supply to the cooling system for the recirculation pump seals.

In Section l. 10 of Suppement 5 to the SER, the staff indicated a similar condi-tion would be required for Unit 2 unless satisfactory resolution was reached on the issue before the licensing of Unit 2.

Three tests have been performed on pumps that are representative of BWR recir-culation pumps in which all seal cooling water was lost.

Although the pump seal cavity temperature exceeded normal operating conditions and pump seal leakage increased following loss of cooling, the observed leakage from the seals was acceptably low.

The first test, which was of the Hanford Unit 2 BWR recirculation pump manufac-tured by the Bingham Pump

Company, was performed at the pump vendor's test facility in July 1973.

During the operability testing of that pump at rated temperature and pressure, plant power to the pump was inadvertently lost.

Upon loss of plant power, the recirculation pump seal cavity was deprived of seal purge (direct injection),

and the pump was unable to recirculate the seal cool-ant through the external heat exchanger.

As a result, the seal cavity tempera-ture exceeded 270OF.

During this event the seal leakage recorder was inopera-tive; however, test personnel continued to monitor pump leakage visually and observed or recorded no leakages beyond the capability of the 1-in. seal drain lines (under 5 gpm).

This is well within the makeup capacity of the reactor core isolation cooling (RCIC) system.

These leakage observations continued for more than 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after cooling was lost.

These test results provide confirma-tion that loss of cooling to the tested Bingham pump seal for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> does not lead to unacceptable seal leakage.

The second test was performed on a Byron Jackson pump in December 1978 by expos-ing the seal to 530OF water and observing and recording seal leakage following a loss of seal cooling water for 30 min.

Although this test duration does not exceed the 2-hour criterion, the peak seal temperature, which is limited by the temperature of the primary system water, was reached during the 30-min test.

Consequently, if any significant seal deterioration were to occur, it would have occurred during this 30-min test period.

The details of the testing and asso-ciated hardware are described in ASME Paper No. 80-C2-PVP-28.

The test results showed a measured seal leak rate of 2.39 gpm, which is well within the makeup capacity of the RCIC system.

Consequently, this test shows that loss of seal cooling for the tested Byron Jackson pump does not lead to unacceptable seal leakage.

The third test was performed on a Byron Jackson (BJ) pump at Byron Jackson Pump Division, Borg-Warner Corp. in Los Angeles in August 1980.

Water at 550'F and 2,300 psig was piped from the discharge leg of a test loop through a test fixture that closely simulated a typical BJ seal cavity and heat exchanger arrangement and back to the suction leg of the test loop.

When the test loop water reached this'temperature and pressure, the cooling water to the test fixture was discontinued and the test commenced.

The test results showed that Susquehanna SSER 6

22-10

the seal leakage remained steady and low (30 cc/hour) for the first 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of'he test.

The test continued for 56 hours6.481481e-4 days <br />0.0156 hours <br />9.259259e-5 weeks <br />2.1308e-5 months <br /> and leakage did not increase appre-ciably.

As with the earlier Byron Jackson test, this test showed that loss of seal cooling to that pump does not lead to unacceptable seal leakage, i.e.,

leakage beyond the makeup capacity of the RCIC system.

The above test results are representative or bounding for BWR recirculation pumps as described below.

(1)

Bingham Pumps - The seal design for the tested pump is the same design and the largest size used in BWR recirculation pump application.

In addition, the test conditions for the tested pump are applicable to BWR recirculation pumps.

The test results are, therefore, applicable to the inplant BWR pumps.

(2)

Byron Jackson (BJ)

Pumps - The test results for the tested BJ pumps are bounding for the BJ pumps used for BWR recirculation systems because (a)

The tested BJ pumps had a three-stage seal assembly with a fourth vapor seal.

General Electric BWR recirculation pumps utilize two-stage seals.

However, because the seal leak rates were small, the impact of the number of stages on the leak rate is also small.

For the BJ pumps in BWR applications, the differential pressure per stage across the seal is approximately 190 psi lower (525 psi vs 716 psi) than for the BJ pump seals tested.

Consequently, the leak rate through the tested pump seal would be higher than that for the inplant BWR pump seal.

(b)

The BJ test seal is a larger size seal than that used in a BWR re-circulation pump, and the expected leakage from the seal would be higher than for a BWR pump.

(c)

Other than the differences identified in (a) and (b), the design of the BJ test seal is similar to that of a typical BJ seal used in BWR recirculation pump application.

Seal leakage data on Bingham and Byron Jackson pumps show the leakage rates to be acceptable following loss of cooling to the pump seals.

The test pumps were typical of recirculation pumps used in BWRs.

Therefore, no modifications to the seal cooling for recirculation pumps are required.

The staff considers this issue resolved for Susquehanna Unit 2.

Susquehanna SSER 6

22-11

APPENDIX A CONTINUATION OF CHRONOLOGY OF NRC STAFF RADIOLOGICAL REVIEW OF SUS(UEHANNA STEAM ELECTRIC STATION, UNITS 1 and 2

Appendix A in the Safety Evaluation Report and Supplements 1, 2, 3, 4, and 5

provided a chronology of the NRC staff's radiological safety review of the application for the period April 10, 1978, to February 11, 1983; the purpose of this appendix is to update that chronology.

February 14, February 16, February 18, 1983 1983 1983 Letter from applicant transmitting the January 1983 Monthly Operating Report.

Letter from Teledyne Engineering Services transmitting Independent Design Review - Susquehanna Steam Electric

Station, Review of Category III Anchors.

Letter from applicant concerning License Condition 2.C. 17(a) of License NPF-14.

February 23; 1983 Letter to applicant concerning Susquehanna Unit 2 seismic and dynamic qualification review and audit.

February 25, 1983 Letter to applicant concerning Nuclear Waste Policy Act of 1982 (PL 97-425).

February 25, 1983 Letter from applicant concerning response to License Condition 2.C(13) of License NPF-14.

February 28, February 28, 1983 1983 February 28, 1983 Letter from applicant concerning Humphrey Issue 3.0.

Letter from applicant concerning qualification of the reactor recirculation discharge valve assemblies

- License Condition 2.C(23) (e).

Letter from applicant concerning operator licensing examina-tion site visits (Generic Letter 83-01 response).

February 28, 1983 Letter from applicant concerning emergency preparedness-Licensing Conditions 2.C(2) (a), (b), and (c).

,March 1, 1983 March 7, 1983 Letter from applicant concerning low level radwaste holding facility - response to NRC questions.

k Letter from applicant concerning request for information-emergency operations facilities.

March 7, 1983 Letter from applicant concerning design assessment

report, Revision 8.

Susquehanna SSER 6

Appendix A

March 9, 1983 Letter from applicant concerning startup testing.

March 10, 1983 Letter to applicant responding to request for exemption from 10 CFR 50.44 requirements based on installation of operable inerting system.

March ll, 1983 March ll, 1983 March 14, 1983 March 14, 1983 March 15, 1983 March 15, 1983 March 16, 1983 Letter from applicant transmitting Amendment 21 to License NPF-14 proposing changes to Appendix A of the Technical Specification regarding typographical and administrative errors.

U Letter from applicant transmitting Revision 3 to Evaluation of Feedwater Check Valves Due to Postulated Pipe Rupture.

Letter from applicant transmitting Exercise Manual for full-scale NRC/Federal Emergency Management Agency-observed emergency preparedness exercise.

Letter from applicant concerning request for exemption from testing.

Letter from applicant transmitting the February 1983 Monthly Operating Report.

1 Letter to applicant requesting information regarding deter-mination of effect operation and maintenance may have on archaeological sites.

Letter from applicant transmitting the 1982 Annual Financial Report.

March 16, 1983 Letter from applicant discussing final results of additional tests of adequacy of design process.

March 17, 1983 March 18, 1983 March 22, 1983

,March 23, 1983 Letter from applicant discussing results of analysis of proposed Transcontinental Gas Pipe Line Corp.

(Transco) natural gas pipeline installation.

Letter from applicant transmitting "Susquehanna Post-Accident Airborne and Plateout Dose Calculation for Equip-ment gualification," per NUREG-0588.

Letter from applicant transmitting revision to National Pollution Discharge Elimination System Permit regarding sewage treatment.

Letter to applicant regarding implementation of Regulatory Guide (RG) 1. 150 (Generic Letter 83-15).

March 23, 1983 Letter from applicant advising that Change N to the physical security plan originally scheduled for February 1983 will be transmitted in April 1983.

Susquehanna SSER 6

Appendix A

March 24, 1983 March 24, 1983 Letter from applicant concerning annual personnel monitoring report.

Letter to applicant concerning NUREG-0977 anticipated transient without scram (ATMS) events at Salem Generating Station, Unit 1 (Generic Letter 83-16).

March 24, 1983 March 24, 1983 March 29, 1983 March 30, 1983 April 4, 1983 Letter to applicant transmitting additional guidance on reporting offsite radiation doses to the public.

Letter from applicant transmitting temporary change notices for emergency plan implementation procedures.

Letter from applicant transmitting 223 oversize updated drawings in accordance with RG 1.70.

Letter from applicant transmitting supporting information on request for one-time exemption from performing integrated leak rate test on containment penetrations.

Letter to applicant concerning ATWS events at Salem (Generic Letter 83-16A).

April 4, 1983 April 4, 1983 Letter from applicant transmitting table complying with Preservice Inspection Program.

Letter from applicant transmitting correction to applica-tion for License Amendment 21.

April 6, 1983 April 7, 1983 Letter from applicant transmitting status of evaluation and results regarding Humphrey issues.

Letter from applicant concerning independent evaluation of Unit 2.

April 7, 1983 April 8, 1983 April 11, 1983 Letter from applicant transmitting payment for additional fees incurred for review of additional technical issue in proposed License Amendment 19 for review of administrative issues in proposed License Amendment 21.

Letter to applicant regarding integrity of requalification examinations for renewal of reactor operator and senior operator licenses (Generic Letter 83-17).

Letter from applicant transmitting Susquehanna Steam Elec-tric Station Offsite Dose Calculation Manual.

April ll, 1983 April 13, 1983 Letter to applicant transmitting Supplement 5 to the SER.

Letter from applicant transmitting Revision 1 to 18-in.

containment purge valve qualification analysis and 24-in.

containment purge valve qualification analysis.

Susquehanna SSER 6

Appendix A

April 13, 1983 Letter from applicant requesting that the review of 'Item 7 of proposed Amendment 15 to Licens'e NPF-14 in letter dated December 10,

1982, be held in abeyance pending further investigation of fuses in use at facility.

April 14, 1983 Letter to applicant transmitting Amendment 13 to License NPF-14.

April 14, 1983 April 15, 1983 April 15, 1983 Letter from applicant transmitting Temporary Change 83-575 to emergency plan procedure.

Letter from applicant transmitting the March 1983 Monthly Operating Report.

Letter from applicant transmitting proposed Amendment 22 to License NPF-14 changing Technical Specifications to incor-porate final setpoint data developed during startup test program.

April 15, 1983 April 15, 1983 April 15, 1983 Letter from applicant advising that maintenance and sur-veillance schedule for components requiring initial main-tenance and surveillance after first year of operation is implemented.

Letter from applicant responding to Generic Letter 82-33, Supplement 1 to NUREG-0737.

Letter to applicant transmitting Amendment 14 to License NPF-14 modifying Technical Specifications 3.9. 1 and 4.9. 1 to enhance operator awareness of testing provisions of reactor mode switch.

April 18, 1983 Letter from applicant advising of negotiation initiation to bring about contract with Department of Energy (DOE) to dispose of spent nuclear fuel or high level radwaste per License Condition 3.

April 20, 1983 April 22, 1983 April 25, 1983 April 25, 1983 April 25, 1983 Letter from applicant transmitting Revision 1 to Emergency Plan Implementing Procedure EP-IP-030.

Letter from applicant informing of discrepancies between Technical Specifications and sample Standard Technical Specifications provided in Enclosure 2 to Generic Letter 83 Modification of Automatic Depressurization System Logic, TMI Item II.K.3.18.

Letter to applicant transmitting an SER on BWR Owners Group generic response to NUREG-0737.

Letter to applicant granting preservice inspection relief requests in letter dated March 3, 1983.

Letter from applicant transmitting 467 oversize drawings in accordance with RG 1.70.

Susquehanna SSER 6

Appendix A

April 27, 1983 Letter to applicant requesting remittance of Class II fee for application regarding nonconformance with NUREG-0737 on containment isolation dependability.

April 28, 1983 April 29, 1983 Letter from applicant responding to questions regarding proposed Amendment 19.

Letter from applicant transmitting application for proposed Amendment 23 to License NPF-14 changing License Condition 2.C to extend completion date for safety parameter display system.

May 2, 1983 Letter to applicant regarding procedures for providing public notice concerning issuance of amendment to service list (Generic Letter 83-19).

May 2, 1983 Letter acknowledging completion of action required by Amend-ment 7 to License NPF-14, Paragraph 3, by initiating DOE negotiations concerning disposal of high level waste or spent nuclear fuel.

May 4, 1983 May 5, 1983 Letter from applicant transmitting proposed Amendment 24 to License NPF-14 changing Appendix A, Technical Specifications, concerning circuit breaker location, gaseous type.

Letter from applicant transmitting "Offsite Dose Calculation Manual."

May 5, 1983 F

Letter from applicant transmitting an application for Amend-ment 54 to the OL application consisting of Revision 33 to the FSAR.

May 6, 1983 May 9, 1983 May 9, 1983 May 10, 1983 Letter from applicant transmitting Change N to the physical security plan.

Letter to applicant concerning integrated scheduling for implementation of plant modes (Generic Letter 83-20).

Letter to applicant requesting additional information con-cerning Revision 6 to the emergency plan.

Letter from applicant transmitting responses to questions concerning ultimate heat sink test plan.

May 10, 1983 May 10, 1983 Letter to applicant concerning gas pipeline near Susquehanna facility - License Condition 2. C(13)(c).

Letter from applicant transmitting the April 1983 Monthly Operating Report.

May 16, 1983 Letter from applicant concerning hydrodynamic loads on con-trol rod drive piping.

Susquehanna SSER 6

'Appendix A

May 16, 1983 May 20, 1983 Letter from applicant concerning response to License Condition 2.C(32) - modifications to resolve the emergency service water single-failure issue.

Letter from applicant concerning equipment qualification summary report.

May 25, 1983 May 25-27, 1983 Letter from applicant concerning fee for NRC review.

Representatives from NRC and PP8 L meet at the site of Susquehanna Unit 2 to assess status of construction and completion schedules.

(Summary issued June 22, 1983.)

May 26, 1983 Letter from applicant transmitting a response to Generic Letter 83-18.

May 26, 1983 Letter from applicant responding to request for additional information - Revision 6 to the emergency plan for Susquehanna.

May 31, 1983 June 15, 1983 Letter from applicant concerning cultural resources.

Letter from applicant concerning Humphrey Issues

3. 1 and

3. 3.

June 15, 1983 Letter from applicant transmitting the May 1983 Monthly Operating Report.

June 17, 1983 Representatives from NRC and PP8L meet in 8ethesda, Maryland, to discuss emergency core cooling system activa-tion instrumentation.

(Summary issued June 29, 1983.)

June 20, 1983 Letter from applicant transmitting a response to SER Supplement 5, Item 3.11.1(1)(C).

June 20, 1983 Letter from applicant transmitting a response to SER Supplement 5 Item 3.11.1(l)(a).

June 27, 1983 Letter from applicant concerning qualification of primary containment vacuum breakers.

June 27, 1983 June 27, 1983 Letter from applicant, concerning License Condition 2. C. 28(f).

Letter from applicant concerning proposed Amendment 25 to License NPF-14.

June 28, 1983 June 29, 1983 Letter to applicant concerning request for additional infor-mation regarding proposed Transco pipeline.

Letter to applicant concerning Susquehanna Unit 2 design reviews.

June 30, 1983 Letter from applicant concerning License Condition 2.C.10.

Susquehanna SSER 6

Appendix A

June 30, 1983 Letter from applicant transmitting Revision 2 to the pump and valve.Inservice Inspection Program July 6, 1983 July 7, 1983 July 7, 1983 Letter to applicant concerning outstanding requests for proposed changes to License NPF-14.

Letter from applicant concerning License Condition 2. C. 25(a).

Letter from applicant concerning TMI Item II.K.3. 18 automatic depressurization system timer setting and justifi-cation for setting.

,July 7, 1983 Letter from applicant concerning additional information regarding the proposed Transco pipeline.

July 11, 1983 July 14, 1983 Letter from applicant concerning Appendix F to Supplement 5.

Letter from applicant transmitting June 1983 Monthly Operat-ing Report.

July 18, 1983 Letter to applicant concerning Issuance of Notices of Con-sideration of Issuance of Amendments.

July 20, 1983 Letter to applicant concerning detailed control room design review program plan.

July 21, 1983 Le'tter to applicant concerning control of heavy loads (Phase I) - NUREG-0612.

July 22, 1983 July 22, 1983 Letter from applicant concerning proposed Amendment 27 to License NPF-14.

Letter from applicant concerning requested changes to Generic Letter 82-33 schedule.

July 22, 1983 Letter from applicant transmitting 6-month response to NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants."

July 26, 1983 July 29, 1983 Letter from applicant concerning additional information to support proposed Amendment 27 to License NPF-14.

Letter from applicant concerning relief request for trans-former replacement.

August 2, 1983 Letter from applicant concerning Unit 2 Preservice Inspec-tion Program and requesting relief.

August 2, 1983 Letter from applicant concerning revision to proposed Amend-ment 27 to License NPF-14.

August 3, 1983 Letter from applicant concerning Unit 2 license conditions.

Susquehanna SSER 6

Appendix A*

August '3, 1983.

August 4, 1983 August 8, 1983 August 15, 1983 August 15, 1983 August 15, 1983 August 17, 1983 August 19, 1983 August 22, 1983 Letter from applicant concerning clarification to the response to Generic Letter 82-33.

Letter from applicant concerning additional clarification on the'elief request for transformer replacement.

Letter fiom applicant concerning proposed Unit 2 Technical Specifications.

Letter from applicant transmitting the July 1983 Monthly Operating Report.

Letter from applicant concerning additional information on proposed Amendment 19 to License NPF-14.

Letter from applicant concerning proposed Amendment 28 to License NPF-14.

Letter from applicant concerning Annual Financial 'Report.

Letter from applicant concerning TMI response for Unit 2.

Letter from applicant concernin'g proposed Amendment 26 to License NPF-14.

August 23, 1983 Letter from applicant concerning Issuance of Notices of Consideration of Issuance of Amendments.

August 24, 1983 August 25, 1983 Letter from applicant concerning modification to emergency service w'ater system.

Letter from applicant concerning independent evaluation of Unit 2 ~

August 26, 1983 August 29, 1983 August 29, 1983 August 31, 1983 September 2,

1983 Letter,from applicant concerning NUREG-0737, Item II.E.4. 2-ganged valve'opening.

Letter from applicant concerning FSAR Section 13.2.

Letter from applicant concerning emergency operating proce-dure for heating, ventilation, and air conditioning.

Letter to applicant requesting additional information on Susquehanna feedwater check valve analysis.

Letter to applicant transmitting Amendment 15 to License NPF"14.

Septembe'r 9, 1983 Letter from applicant concerning Equipment gualification Summary Report, Revision 4 - response to SER Supplement 5

Items 1.9 and 3.11.1(l)(a) and 10 CFR 50.49(i).

September 12, 1983 Letter from applicant transmitting the August 1983 Monthly Operating Report.

Susquehanna SSER 6

Appendix A

September 13.,

1, September 15, 1983 1983 Letter to applicant transmitting Issuance of Notices of Consideration of Issuance of Amendments.

Letter from applicant transmitting additional information concerning proposed Amendment 26 to License NPF-14.

September 15, 1983 Letter from applicant concerning relief request for trans-former replacement.

September 15, September 15, September 16, 1983 1983 1983

'etter from applicant concerning FSAR Section

7. 1.

Letter from applicant concerning FSAR Section 7.4.

Letter to applicant concerning drywell-to-wetwell vacuum breaker valves.

September 20, 1983 Letter to applicant concerning Susquehanna automatic de-pressurization system (ADS) timer setting.

September 22, 1983 Letter from applicant concerning License Condition 2.C.25(b) of License NPF-14.

September 23, September 26, September 28, September 28, 1983 1983 1983 1983 Letter from applicant concerning SER Supplement 5, Sec-tion 1. 10, Item '(10) - installation of debris screens on drywell containment purge system.

Letter from applicant transmitting revised FSAR sections concerning installation of new engineered safety system transformers, retention of construction substation, and update of stability analysis.

Letter to applicant concerning diesel generator sur veil-lance requirement Technical Specification 4. 8. l. 1. 2. d. 12.

Letter to applicant transmitting Amendment 16 to License NPF-14.

September 29, I 'h September 29, 1983 1983 Letter from applicant concerning 9-month response.

NUREG-0612 - Unit 2 Letter to applicant concerning nonconformance with NUREG-0737, Item II.E.4.2.

September 30, September 30, 1983 1983 Letter from applicant concerning Letter from applicant concerning safety parameter display system.

FSAR Section

3. 13.

safety evaluation of the October 3, 1983 October 3, 1983 October 6, 1983 Letter from applicant concerning SER Issue No. 112.

Letter from applicant concerning FSAR Section 7.5.

Letter from applicant concerning FSAR Section 3.6A.

Susquehanna SSER 6

Appendix A

October 6, 1983 October 6, 1983 October 7, 1983 October 7, 1983 October 10,'983 Letter from applicant concerning FSAR Section 10.4.

Letter from applicant concerning FSAR Section

12. 2.

Letter from applicant concerning proposed Amendment 30 to License NPF-14.

Letter from applicant concerning FSAR Section 7.7.

Letter from applicant concerning new final rule, 10 CFR 50.72.

October 10, 1983 October 12, 1983 October 12, 1983 October 13, 1983 October 13, 1983 October 13, 1983 October 14, 1983 October 20, 1983 Letter from applicant concerning SER Supplement 5,

Section 1.9, "Loss of Non-Class lE Instrumentation and Control Power System Bus During Operation."

Letter from applicant concerning spray pond report.

Letter from applicant transmitting the September 1983 Monthly Operating Report.

Letter from applicant concerning FSAR Section

9. 1.

I Letter from applicant concerning startup test program.

Letter from applicant concerning preoperational test pro-gram for Unit 2.

Letter from applicant concerning FSAR Section 9.3.

Letter from applicant concerning proposed Amendment 31 to License NPF-14.

October 20, 1983 October 24, 1983 October 24, 1983 October 24, 1983 October 25, 1938 Letter from applicant concerning position on diesel start requirement.

Letter from applicant concerning drywell-to-wetwell vacuum breakers.

Letter from applicant concerning proposed Amendment 32 to License NPF-14.

III Letter from applicant concerning change to service list.

Letter to applicant concerning clarification of required actions based on generic implications of Salem ATWS events (Generic Letter 83-28).

October 28, 1983 Letter from applicant requesting approval of Code Case N-253-2.

October 28, 1983 Letter from BWR Owners Group (T. J.

Dente) to NRC (D. Eisenhut) concerning NUREG-0737, Item II.K.3. 18, "Modification of Automatic Depressurization Logic."

Susquehanna SSER 6

10 Appendix A

October 31, 3,983 October 31, 1983 Letter to applicant concerning review of Revision 6 to the emergency plan for Susquehanna, Units 1 and 2.

Letter to applicant transmitting EG&G "Control of Heavy Loads at Nuclear Power Plants, Susquehanna Steam Electric Station, Unit 2, Phase I."

November 1, 1983 November 2, 1983 Letter from applicant transmitting Revision 1 to preservice inspection plan and Revision 0 to preservice inspection relief requests 8 through 12 in connection with SER Item 111.

Letter to applicant transmitting Amendment 17 to License NPF-14.

November 3, 1983 November 3, 1983 Letter from applicant responding to staff questions on environmental qualification.

Letter from applicant responding to questions and forwarding equipment qualification report.,

November 4, 1983 Letter from applicant concerning proposed Amendment 34 to License NPF-14.

November 7,

1983 Letter from applicant requesting exigency for proposed Amendment 31 to License NPF-14.

November 7, 1983 November 8, 1983 November 8, 1983 November ll, 1983 November 11, 1983 Letter from applicant concerning RG 1.97 modifications for Unit 2 - environmental qualifications.

Letter from applicant concerning environmental protection pl an.

Letter to applicant requesting additional information regarding submittals for License Conditions 2.C.(25)(a) and 2.C.(25)(b).

Letter from applicant concerning control room design review summary report.

Letter from applicant concerning safety parameter display system (SPDS) configuration clarifications.

November ll, 1983 Letter from applicant concerning FSAR Section 3.4.

November ll, 1983 Letter from applicant concerning License Condition 2. C(13).

November 14, 1983 November 17, 1983 Letter from applicant transmitting the October 1983 Monthly Operating Report.

Letter to applicant concerning use of ASME Code Case N-253.2.

Susquehanna SSER 6

Appendix A

November 21, 1983 Letter from applicant transmitting proprietary reyqrt, "Evaluation of NUREG-0783 Local Pool Temperature Limits f'r Susquehanna Steam Electric.Station," in response to License Condition 2.C..29.

Report withheld from public disclosure pursuant to 10 CFR 2.790.

November 21, 1983 Letter from applicant concerning FSAR Section 7.3.

November 29, 1983 Letter from applicant concerning fuel load schedule for Unit 2.

December 5,

1983 December 6,

1983 December 7, 1983 Representatives from NRC and PP&L meet in Silver Spring,

Maryland, NRC offices to discuss proposed changes to physical security plan (closed meeting).

Letter from applicant concerning justification regarding proposed Amendment 25 to License NPF-14.

Letter from applicant concerning response to request for additional information on proposed Amendment 54 to License NPF-14.

December 8, 1983 Letter from applicant concerning proposed Amendment 33 to License NPF-14.

December 8, 1983 December 9,

1983 Letter to applicant concerning status of outstanding items to support operating license for Susquehanna Unit 2.

Letter from applicant concerning proposed Amendment 35 to License NPF-14.

December 12, 1983 Letter to applicant transmitting Amendment 19 to License NPF-14.

December 12, 1983 December 13, 1983 Letter to applicant transmitting Amendment 20 to License NPF-14.

Letter from applicant concerning NUREG-0612 - Unit 2 9-month response, equipment qualification.

December 13, 1983 Letter from applicant concerning FSAR Section 12.3.

December 13, 1983 Letter from applicant concerning vent and purge valves.

December 13, 1983 Letter from applicant concerning fire protection - request for variance.

December 13, 1983 Letter from applicant concerning Unit 2 Seismic gualifica-tion Review Team status update.

December 15, 1983 Letter from applicant transmitting the November 1983 Monthly Operating Report.

Susquehanna SSER 6

12 Appendix A

December 16, 1983 December 19, 1983 Letter from applicant clarifying additional information submitted in December 1982 for proposed Amendment 53 to License NPF-14.

Letter from applicant concerning proposed Amendment 36 to License NPF-14.

December 21, 1983 Letter from applicant transmitting final spray pond report.

December 21, 1983 Letter from applicant concerning initial test program-Unit 1/Unit 2 differences.

December 21, 1983 Letter from applicant transmitting revisions to FSAR Section 14.2.

December 21, 1983 Letter from applicant concerning SER Item No.

111.

December 21, 1983 Letter from applicant concerning a response to request for additional information on equipment qualification.

December.21, 1983 Letter from applicant concerning facility staffing survey.

December 29, 1983 December 30, 1983 Letter from applicant transmitting additional test abstracts to FSAR Section 14.2 for preoperational and acceptance tests.

Letter from applicant concerning qualification of Unit 2 RG 1.97 modifications.

December 30, 1983 Letter to applicant concerning conformance to RG 1.97, Revision 2.

January 5, 1984 January 5, 1984 Letter from applicant concerning fast cold starts of diesel generators (Generic Letter 83-41).

Letter from applicant transmitting Revision 1 to proposed Amendment 36 to License NPF-14.

January 5, 1984 Letter from applicant transmitting a response to NRC request for information on environmental qualification.

January 10, 1984 January ll, 1984 Letter from applicant concerning the level switch dynamic qualification - SSER 3, Section

3. 10.2.2.

Letter from applicant concerning equipment qualification-target rock solenoid valves.

January 12, 1984 Letter from applicant transmitting Monthly Operating Report-December 1983.

January 18, 1984 Letter from applicant concerning the safety parameter display.

January 19, 1984 Letter from applicant concerning THI Item II.K.3. 25.

Susquehanna SSER 6

13 Appendix A

January 21, 1984 Letter from -applicant transmitting Revision 2 to proposed Amendment 36 to License NPF-14.

January 23, 1984 Letter from applicant concerning emergency planning exer-cise exemption request.

January 25, 1984 January 27, 1984 Letter from applicant concerning FSAR Section 14.2.

Letter from applicant concerning NUREG-0803 BWR Owners Group endorsement.

January 31, 1984 Letter from applicant concerning SER Supplement 5,

Section 1.10, Item (14) - Nuclear steam supply'system-.

vendor review of procedures.

February 1, 1984 Letter from applicant concerning dynamic qualification of the standby liquid control'xplosiv'e valve.

February 1, 1984 Letter from applicant concerning SPDS completion schedule.

February 2, 1984 Letter to applicant concerning review of detailed control room design review summary report.

February 2, 1984 Letter from applicant concerning license conditions for Unit 2 license.

February 2, 1984 Letter from applicant concerning response to Generic Letter 84-01.

February 3, 1984 February 8, 1984 Letter from applicant concerning feedwater lines.

Letter from applicant concerning hydrodynamic loads on control rod dr'ive piping.

February 9, 1984 Letter to applicant concerning deletion of home telephone

numbers, unlisted utility numbers, etc.

from emergency plans.

February 10, 1984 February 13, 1984 Letter from applicant transmitting an application for amendment of Construction Permit CPPR-102 to extend the construction completion date.

Letter from applicant concerning control room design review.

February 14, 1984 Letter from applicant transmitting the January 1984 Monthly Operating Report for Susquehanna Unit 1.

February 21, 1984 Letter from applicant concerning additional information regarding th'e proposed Transco pipeline.

February 22, 1984 Letter from 'applicant concerning TMI Item II.K.3.18.

Susquehanna SSER 6

Appendix A

February 22, 1984 Representatives from NRC and PAL meet in Bethesda, Maryland, to discuss proposed changes to standby gas treatment system Technical Specifications.

(Summary issued March 14, 1984)

February 27, 1984 Representatives from NRC and PP&L meet in Bethesda, Maryland, to discuss Revision 7 of the Susquehanna Emergency Plan.

February 27, 1984 Letter from applicant concerning common power supply and sensor malfunction study for Unit 2.

March 15, 1984 Letter from applicant concerning boiling-water reactor core stability.

Susquehanna SSER 6

15 Appendix A

APPENDIX B BIBLIOGRAPHY American Society of Mechanical Engineers, Paper No. 80-C2-PVP-28, "Loss of Component Cooling Water Capability of a PWR Reactor Coolant Pump,"

by A.

H-C Marr, 1980.

American Water Works Association (AWWA) C504-80, "Standard for Rubber-Seated Butterfly Valves," revised Jan.

28, 1980.

BWR Owners Group, SLI-8211, "Review of BWR Reactor Water Level Measurement Systems," July 1982.

---, SLI-8218, "Inadequate Core Cooling Detection in BWRs," Nov. 12, 1983.

EG&G Idaho, Inc., review of Pennsylvania Power 8 Light Co. submittal, dated

July 22, 1983, forwarding 6-month response to NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants."

Federal Re ister, 48 FR 24008, U. S. Nuclear Regulatory Commission, 10 CFR Part 50, Final Rule, Fracture Toughness Requirements for Light-Water Nuclear Power Reactors,"

May 27, 1983.

General Electric Company, NEDE-22178-P, "Mark II Containment Drywell-to-Wetwell Vacuum Breaker Models," Aug.

1982 (proprietary - not publicly available).

---, Topical Report NED0-22209, "Analysis of Scram Discharge Volume System Piping Integrity," Aug. 1982.

---, Topical Report NED0-24342, "GE Evaluation in Response to NRC Request Regarding BWR Scram System Pipe Breaks," Apr. 1981.

Letter, Feb.

4, 1981, from D.

B. Waters (BWR Owners Group) to D.

G. Eisenhut (NRC),

Subject:

Additional Preoperational Tests and Augmented Operator Training During Startup.

---, June 17, 1983, from D.

M. O'Conner (Bechtel Power Corporation) to R.

W. Houston (NRC),

Subject:

AGCO Vacuum Breaker Test Program.

---, June 29, 1983 (Generic Letter 83-24),

from D.

G. Eisenhut (NRC) to all BWR Applicants for an Operating License and Holders of Operating Licenses for Grand Gulf, La Salle, and Susquehanna,

Subject:

TMI Task Item I.G., "Special Low Power Testing and Training, Recommendations for BWRs."

-, July 25, 1983, from D.

G. Eisenhut (NRC) to T. J.

Dente (BWR Owners Group),

Subject:

Safety Concerns With Pipe Breaks in the BWR Scram System.

---, Nov. 18, 1983, from D.

R. Helwig (BWR Owners Group) to D.

G. Eisenhut (NRC),

Subject:

Scram Discharge Piping.

Susquehanna SSER 6

Appendix B

Pennsylvania Power 8 Light Company, "Final Safety Analysis Report, Susquehanna Steam Electric Station, Units 1 and 2," dated Apr. 1981 (Dockets 50-387 and 50-388).

U.S.

Nuclear Regulatory Commission, NUREG-0484, "Methodology for Combining Dynamic Responses,"

Rev.

1, May 1980.

NUREG-0487, "Mark II Lead Plant Program Evaluation Report,"

Nov. 1978.

NUREG-0588, "Interim Staff Position on Environmental gualification of Safety-Related Electrical Equipment,"

Nov. 1979; Rev.

1, July 1981.

---, NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants - Resolution of Generic Technical Activity A-36," July 1980.

---, NUREG-0737, "Clarification of TMI Action Plan Requirements,"

Nov. 1980; Supplement 1, Jan.

1983.

---, NUREG-0776, "Safety Evaluation Report Related to the Operation of Susquehanna Steam Electric Station, Units 1 and 2," Apr. 1981; Supplement 1,

June 1981; Supplement 2, Sept.

1981; Supplement 3, July 1982; Supplement 4,

Nov. 1982; Supplement 5, Mar.

1983.

---, NUREG-0783, "Suppression Pool Temperature Limits for BWR Containments for Generic Technical Activity A-39" (to be issued pending approval by Committee to Review Generic Requirements).

---, NUREG-0800, "Standard Review Plan for Review of Safety Analysis Reports for Nuclear Power Plants,"

Rev.

2, July 1981.

NUREG-0803, "Generic Safety Evaluation Report Regarding the Integrity of BWR Scram System Piping," Aug.

1981.

---, NUREG-0808, "Mark II Containment Program Load Evaluation and Acceptance Criteria," Aug. 1981.

---, NUREG-0977, "NRC Fact-Finding Task Force Report on the ATWS Event at

'Salem Nuclear Generating Station, Unit 1, on February 22 and 25, 1983,"

Mar.

1983.

U.S. Nuclear Regulatory Commission, Office of Inspection and Enforcement, Bulletin (IEB)79-01B, "Environmental gualification of Class lE Equipment,"

Jan.

14, 1980, and supplements dated Feb.

29, Sept.

30, and Oct.

24, 1980.

IEB 79-27, "Loss of Non-Class lE Instrumentation and Control Power System Bus During Operation,"

Nov. 30, 1979.

Susquehanna SSER 6

Appendix B

APPENDIX H REVIEW OF THE PRESERVICE INSPECTION PROGRAM FOR SUSQUEHANNA UNIT 2 H. 1 INTRODUCTION For nuclear power facilities whose construction permits were issued on or after January 1, 1971, but before July 1, 1974, 10 CFR 50.55a(g)(2) specifies that components shall meet the preservice examination requirements set forth in Editions of Section XI of the ASME Code -in effect 6 months before the date of issuance of the construction permit.

The provisions of 10 CFR 50. 55a(g)(2) also state that the components (including supports) may meet the requirements set forth in subsequent editions and addenda of this Code which are incorporated by reference in 10 CFR 50.55a(b),

subject to the limitations and modifications listed therein.

In letters dated August 2, 1983, November 1, 1983, and December 21, 1983, Pennsylvania Power L Light Company (the applicant) submitted requests for relief from Code requirements and provided supporting information pursuant to 10 CFR 50.55a(a)(2)(i).

Therefore, the staff's evaluation consisted of review-ing the applicant's submittals to the requirements of the 1974 Edition of Section XI through Summer 1975 Addenda and determining if relief from the Code requirements were justified.

As a result of its review of this information, the staff has determined that certain, preservice examinations are impractical and performing these required examinations would result in hardships or unusual difficulties without compen-sating increase in the level of quality and safety.

The basis for this conclu-sion is discussed in the subsequent paragraphs of this appendix.

H. 2 TECHNICAL REVIEW CONSIDERATIONS (1)

The construction permit for Susquehanna Unit 2 was issued on November 2, 1973.

In accordance with 10 CFR 50.55a(g)(2),

components (including supports),

which were classified as ASME Code Class 1 and 2, must be de-signed and provided with access to enable the performance of required in-service and preservice examinations set forth in the 1971 Edition of ASME Code,Section XI, including the Addenda through Summer 1972.

The ASME first published rules for inservice inspection in the 1970 Edition of Sec-tion XI.

No preservice or inservice inspection requirements existed before that date.

Because the plant system design and ordering of long lead-time components were well under way by the time Section XI rules became effec-tive, full compliance with the exact Section XI access and inspectability requirements of the Code were not always practical.

The applicant optionally revised the Preservice Inspection (PSI) Program on the basis of the requirements of the 1974 Edition through Summer 1975 Addenda in con-sideration of the updating requirements of 10 CFR'0.55a(g) for inservice inspection.

Susquehanna SSER 6

Appendix H

(2)

Verification of as-built structural integrity of the primary pressure boundary is not dependent on the Section XI preservice examination.

The applicable construction codes to which the Susquehanna Unit 2 primary pressure boundary was fabricated contain examination and testing require-ments that by themselves provide the necessary assurance that the pressure boundary components are capable of performing safely under all operating conditions reviewed in the Final Safety Analysis Report and described in the plant design specification.

As a part of these examinations, all of the primary pressure boundary full penetration welds were volumetrically inspected (radiographed) and the system was subjected to hydrostatic pressure tests.

(3)

The intent of the preser vice examination is to establish a reference or baseline before the initial operation of the facility.

The results of sub-sequent inservice examinations can then be compared with the original con-dition to determine if changes have occurred.

If review of the inservice inspection results shows no change from the original condition, no action is required.

In the case where baseline data are not available, all indi-cations must be treated as new indications and evaluated accordingly.

Sec-tion XI of the ASME Code contains acceptance standards that may be used as the basis for evaluating the acceptability of such indications.

Other benefits of the preservice,examination include providing redundant or alternative volumetric inspection of the primary pressure boundary using a

test method different from that employed during the component fabrication.

Successful performance of preservice examination also demonstrates that the welds so examined are capable of being inspected during the subsequent in-service examination using a similar test method.

In the case of Susquehanna Unit 2, a large portion of the preservice exam-ination required by the ASME Code was performed.

The staff has concluded that failure to perform a lOOX preservice examination of the welds identi-fied below will not. significantly affect the assurance of the initial structural integrity.

In some instances where the required preservice examinations were not performed to the full extent specified by the applicable ASME Code, the staff will require that these or supplemental examinations be conducted as part of the inservice inspection program.

The staff has concluded that requiring these supplemental examinations to be performed at=this time (before plant startup) would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety.

The performance of supplemental examinations, such as surface examinations, in areas where volumetric inspection is difficultwill be more meaningful after a period of operation.

Acceptable preoperational integrity has already been established by similar Section III (ASME Code) fabrication examinations.

In cases where parts of the required examination areas cannot be effec-tively examined because of a combination of component design or current inspection technique limitations, the staff will continue to evaluate the development

.,of new or improved volumetric examination techniques.

As im-provements in these areas are achieved, the staff will require that these Susquehanna SSER 6

Appendix H

new techniques be made a part of the inservice examination requirements fqr those components or welds which received a limited preservice examination.

H. 3 EVALUATION OF RELIEF REQUESTS The applicant requested to use the requirements of subsequent editions and addenda of the Code, which the staff has evaluated and found acceptable, because these new requirements are referenced in the regulations.

These requests are identified in Section H.3.9, which follows.

Evaluation of the remaining relief requests is summarized below.

(Unless other-wise stated, references to the Code refer to the ASME Code,Section XI, 1974 Edition, including Addenda through Summer 1975. )

On the basis of the information submitted by the applicant and the staff's review of the design,

geometry, and materials of construction of the compo-nents, certain preservice requirements of the ASME Code,Section XI, have been determined to be impractical; imposing these requirements would result in hard-ships or unusual difficulties without a compensating increase in the level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(a)(2),

the staff's conclusions that these preservice requirements are impractical are justified as follows.

H.3. 1 All Class 1 and Class 2 Pi in S stems Re uirin Ultrasonic Examination as the Method of Examination Relief Re uest 81 Code Re uirement Ultrasonic examination shall be conducted in accordance with the provisions of Appendix I (Section XI, ASME Code).

Where Appendix I (I-2000) is not applicable, the provisions of Article 5 of Section V (ASME Code) shall apply.

Code Relief Re uest The applicant requested to use Appendix III of Section XI from the Winter 1975 Addenda in lieu of ASME Code,Section V, Article 5, for piping examination.

Reason for Re uest Appendix III, 1977 Edition to the Summer 1978 Addenda, has been accepted for use by incorporation of this Edition and Addenda into 10 CFR 50. 55a.

Appendix III, Winter 1975 Addenda, closely parallels the later Code except that the required examination volume is more conservative in the Winter 1975 Addenda (i.e.,

Figure IWB-3514.1(a) of Winter 1975 compared with Figure IWB-2500-8 of the 1977 Edition).

Staff Evaluation Section XI of the ASME Code, Summer 1975 Addenda, does not specifically provide volumetric inspection methods for welds in piping, but references Article 5 of Section V.

The provisions of 1975 Section V do not specifically address piping welds either, nor do they stipulate recording levels for ultrasonic flaw indica-tions.

Appendix III of Section XI gives specific guidance for ultrasonic Susquehanna SSER 6

Appendix H

examination of piping systems.

However, recording criteria for ultrasonic indications differ between Appendix III and Article 5 of Section',

which re-quires that all indications exceeding 20X of the reference level be investi-gated.

The applicant's procedures require that indications exceeding 50X of the reference level be recorded.

Recording and evaluating indications that exceed 20X but are less than 50X distance amplitude correction (DAC) are diffi-cult for the following reasons:

(1)

The welded joints in nuclear piping frequently contain Code-allowable wall thickness differences (l2X of nominal thickness) as well as weld drop-

through, counterbore

taper,

'crown height, and other surface conditions that generate a large number of geometric reflectors which produce ultrasonic testing (UT) indications greater than 20X DAC.

(2)

Weld metal in,stainless steel piping contains reflectors because of the metallurgical structure, which produce a large number of UT indications.

The staff has determined that Appendix III of Section XI is an acceptable alter-native because it is technically acceptable and is also referenced in 10 CFR 50.55a(b).

On the basis of the fabrication examination required by Section III, the staff concluded that a recording level of 50X is acceptable for the pre-service inspection.

However, for the inservice inspection, the staff has deter-mined that recording at a 50X level is acceptable with the following conditions:

(1)

All indications 50X DAC or greater shall be recorded.

(2)

All indications 100X DAC or greater shall be investigated by a Level II or Level III examiner to the extent necessary to determine the shape, identity, and location of the reflector.

(3)

Any cracklike indication, 20X DAC or greater, discovered during a UT exam-ination of piping welds and base metal materials shall be recorded and in-vestigated by a Level II or Level III examiner to the extent necessary to determine the shape, identity, and location of the reflector.

The appli-cant should take appropriate action concerning all reflectors that are not metallurgical or geometric in origin.

H. 3. 2 Reactor Pressure Vessel Examination Relief Re uest ¹4 Code Re uirement An ultrasonic examination of the reactor pressure vessel shall be performed in accordance with Appendix I, "Ultrasonic Examination," contained in the 1974 Edition of Section XI including Addenda through Summer 1975.

Code Relief Re uest Relief was requested to use the examination requirements stated in the 1974 Edition through Winter 1975 Addenda of Section XI.

Reason for Re uest Use of the Winter 1975 Edition of ASME Code,Section XI, for reactor pressure vessel examination is justified for the following reasons:

Susquehanna SSER 6

Appendix H

(1)

The, major differences applicable to the reactor pressure vessel between the Summer 1975 Addenda and the Minter 1975 Addenda are:

(a)

Table IWB-2500, Examination Category 8-A revision; however, for pre-service examination, this change has no impact.

(b)

Acceptance standards were added and/or changed; however, all changes were more conservative.

(c)

Changes were made to Appendix I; however, primary changes were made to correct typographical errors or to provide clarification.

(d)

Personnel qualification requirements were expanded and were made more conservative (IMA-2300).

(2)

Areas forming the basis for not accepting the use of Winter 1975 Addenda are not applicable to Susquehanna Unit 2 reactor pressure vessel (RPV) preservice examination.

Staff Evaluation The staff has evaluated the differences between the Minter 1975 Addenda and Summer 1975 Addenda of Section XI'taffevaluation has shown that there are no significant technical changes in examination requirements between the subject Code addenda.

The staff, therefore, has determined that an ultrasonic examina-tion of the reactor vessel based on Appendix I in the Winter 1975 Addenda is an acceptable alternative to the ASME Code requirement defined in 10 CFR 50.55a(g)(2).

H.3.3 Reactor Pressure Vessel Head Meridional Weld Seams DA DB DC DD DE and DF Relief Re uest 05 Code Re uirement Examination Category B-A of ASME Code,Section XI, 1974 Edition to Minter 1975

Addenda, requires volumetric examination of essentially 100K of the accessible length of each meridional weld in vessel heads.

Appendix I, Article I-5000, requires the examinations be conducted using two beam angles from each direction (nominal angle" of 45 and 60').

These examinations must be performed completely as a preservice examination requirement before initial plant startup.

Code Relief Re uest Relief was requested from performing 100K of the Section XI examination requirements.

Reason for Re uest Interference from the vessel skirt attachment weld buildup results in the unexamined volumes as follows:

Susquehanna SSER 6

Appendix H

0 base metal examination 0'eld metal examination 45'xamination 60'xamination 12X missed 12'issed 4X missed 2X missed Physical limitations because of the geometry of the reactor vessel result in the above unexamined volumes for the subject welds.

The applicant's documentation shows the. following:

(1)

A composite of all examination angles shows that a volume equal to 2X of the required examination volumes for welds DA, DB, DC, DD, DE, and DF is completely unexamined.

All other areas have been covered by any or all of the 0', 45

, and 60'cans.

(2)

The integrity of the welds has been verified by ultrasonic and magnetic particle testing during fabrication.

(3)

Welds are visually examined for leakage during RPV hydrotest.

Staff Evaluation The meridional welds in the vessel head are physically inaccessible for inspec-tion because of the existing design.

The staff concludes that the limited Sec-tion XI volumetric examination, the volumetric and surface examination performed during fabrication, and the hydrostatic test demonstrate an acceptable level of preservice structural integrity.

H.3.4 Class 1 Valves Exceedin 4-in.

Nominal Pi e Size and Class 1 Reactor Recirculation Pum Casin s

Relief Re uest ¹6 Code Re uirement Category 8-M-2 of ASME Code,Section XI, 1974 Edition to Summer 1975 Addenda, requires visual examination of the internal pressure boundary surfaces on valves exceeding 4-in.

nominal pipe size.

One valve in each group of valves of the same constructional design must be inspected.

Category 8-L-2 of ASME Code,Section XI, 1974 Edition to Summer 1975 Addenda, requires visual examination of the internal pressure boundary surfaces of one pump in each group of pumps performing similar functions in the system.

Code Relief Re uest Relief was requested from the preservice visual examination of internal pressure boundary surfaces for Class 1 valves greater than 4-in.

nominal pipe size and visual examination of reactor recirculation pump internal surfaces.

Reason for Relief Re uests The justification for requesting relief from ASME Code,Section XI, preservice examination requirements is as follows:

(1)

The structural integrity of the piping pressure boundary has been verified by construction code testing requirements.

Susquehanna SSER 6

Appendix H

(2)

The body, bonnet, and disc of the valves have received shop surface exam-inations, i.e., liquid penetrant and/or magnetic particle.

Radiography was also performed on the body.

(3)

The pump casings received radiographic and penetrant testing before being machined.

All machined surfaces were penetrant tested, and pumps were hydrostatic leak tested after final machining.

(4)

All pressure-retaining materials have met ASME Code,Section III, speci-fications, which require visual examination of the casting or forging surfaces free of injurious defect.

Staff Evaluation The intent of the visual examination required by the Code is the detection of corrosion and wear during service.

The staff has determined that the manufac-turer's fabrication examinations exceed Section XI nondestructive examination requirements'and, therefore',

are acceptable as an alternative for the required visual examination.

The staff concluded that the fabrication examinations and Section XI hydrostatic tests demonstrate adequate evidence of preservice integ-rity.

In addition, the applicant has committed to perform the visual examina-tions in the event that the components become accessible during maintenance activities.

H.3.5 Class 2 Cate or C-F and'C-G Pressure-Retainin Welds in Core S ra and Residual Heat Removal Pum s (Relief Re uest 87 Code Re uirements Category CF/CG Table IWC-2600, Item Number C3.1 of ASME Code,Section XI, 1974 Edition to Summer 1975 Addenda, requires full volumetric examination of 100'nd 50K, respectively, of pump casing welds.

These examinations must be performed completely as a preservice examination requirement before initial plant startup.

Relief Re uest Relief is requested from the volumetric examinations required in Section XI.

Reason for Re uest The justification for requesting relief from ASME Code,Section XI, examina-tion requirements is as follows:

(2)

The structural integrity of the pump pressure boundary has been estab-lished by ASME Code,Section III, radiography and liquid penetrant testing requirements.

Accessible pump casing welds have been satisfactorily inspected to ASME Code,Section XI'3)

Pump installation meets manufacturer requirements.

Susquehanna SSER 6'ppendix K

Staff Evaluation Because of the installation design of the pumps listed in Table H.l, the welds are totally encased in concrete and are inaccessible.

Subseque'nt approved edi-tions of the Code, 1977 Edition, including Summer.1978

Addenda, IWC-1230, ad-dress the issue of exemption components encased in concrete.

10 CFR 50.55a(g)

~ permits updating to newer approved editions of the Code.

The applicant's sub-mittal discusses the safety significance of failure of individual pumps.

The staff has reached the conclusion that the volumetric and surface examination performed during fabrication and the hydrostatic test, demonstrate an acceptable level of preservice structural integrity.

H.3.6 Class 1 Examination Cate or B-J and Class 2 Examination Cate pries C-F and C-G Circumferential Butt Welds Relief Re uests 88 89 and 810 Code Re uirement Category B-J requires that the examination areas shall include essentially 100X of the longitudinal and circumferential welds and the base metal for one wall thickness beyond the edge of the weld.

In the case of pipe branch connections, the areas shall include the weld metal, the base metalfor one pipe wall thick-ness beyond the edge of the weld on the main pipe run, and at least 2 in. of the base metal along the branch run.

Categories C-F and C-G require volumetric examination of circumferential butt welds, longitudinal weld joints in welded fittings, and branch connections ex-ceeding 4-in. diameter, including the weld metal and base metal for one wall thickness, by a sampling procedure defined by IWC-2520.

Code Relief Re uest Relief was requested from performing 100K of the Code-required examination.

Reason for Re uest Relief is requested from the ASME Code,Section XI, examination requirements on the basis of partial inaccessibility of the weld and required volume as a

result of plant design.

The applicant has identified the piping system welds that are impractical to examine in Table H. 2.

The applicant has described in his submittals the fabrication examination performed on each weld and the safety significance of not performing the examination required in Section XI.

Staff Evaluation The staff has determined that examination of the welds in Table H.2 to the extent required by the Code is impractical because of the design of the piping system and/or location of piping hangers and suppports.

The applicant conducted surface examinations on those areas that cannot be completely scanned by the ultrasonic inspection.

The staff concludes that the limited Section XI examina-tions, the volumetric examinations performed during fabrication, and the hydro-static test demonstrate an acceptable level of preservice structural integrity.

Susquehanna SSER 6

Appendix H

H.3.7 Class 2 Pressure-Retainin Vessel Welds and Nozzle Welds in the Residual Heat Removal Heat Exchan er Relief Re uest ¹ll Code Re uirement Category C-A of ASME Code,Section XI, 1974 Edition to Summer 1975 Addenda, requires volumetric examination of shell and head circumferential discontinuity welds and base material for one plate thickness beyond the edge of the weld j0 1 n't.

Category C-B of ASME Code,Section XI, 1974 Edition to Summer 1975 Addenda, re-quires volumetric examination of 100'f the nozzle-to-vessel attachment welds.

These examinations must be performed completely once as a preservice examination requirement before initial plant startup.

Code Relief Re uest Relief is requested from 100K of the volumetric examinations required by Section XI.

Reason for Re uest The justification for requesting relief from ASME Code,Section XI, preservice examination requirements is as follows:

(1)

The structural integrity of the pressure boundary has been verified by ASME Code,Section III, construction code testing requirements.

(2)

Accessible portions of the welded attachments have been satisfactorily inspected to ASME Code,Section XI.

Staff Evaluation Physical limitations resulting from the design of the residual heat removal heat exchangers result in uninspectable portions of the welds listed in Table H.3.

The staff concludes that the limited Section XI volumetric examinations per-formed during fabrication and the hydrostatic test demonstrate an acceptable level of preservice structural integrity.

H.3.8 Feedwater Inlet Nozzles N4A and N4D Relief Re uest ¹12

, Code Re uirement Category B-D requires a 100K preservice volumetric examination of the no'zzle-to-vessel weld and adjacent areas of the nozzle-to-vessel weld.

Code Relief Re uest Relief was requested from performing 100K of the ultrasonic examination requirements.

Susquehanna,SSER 6

Appendix H

Reason for Re uest The proximity of nozzles NllA and B to the subject feedwater nozzles precludes complete examination of weld seams N4A and N4D as follows:

N4A 300' completely examined (automatic) 60~ - not examined because of interference from nozzle N11A N4D 300' completely examined (automatic) 60' not examined because of interference from nozzle NllB Spacing of only 4.5 in.

between the nozzles allows only a best-effort manual examination of the affected areas.

The applicant's documentation shows the following:

(1)

The excluded area is 16.67K of the weld seam; 83.33K has been completely examined.

(2)

Four nozzles of the same configuration and service (N4B, N4C, N4E, and N4F) have been completely examined.

(3)

The integrity of welds has been verified by ultrasonic and magnetic particle examination during fabrication.

(4)

All N4 nozzle-to-vessel welds were liquid penetrant tested following RPV hydrotest and accepted.

Staff Evaluation Physical limitations because of the design of the reactor vessel (i.e., location of nozzles NllA and B) result in the above unexamined volumes for the subject welds.

The staff concludes that the limited Section XI volumetric examination, the volumetric and surface examinations performed during fabrication, and the hydrostatic test demonstrate an acceptable level of preservice structural integrity.

I H.,3. 9 Additional Relief Re uests In addition to the relief requests evaluated in Sections H. 3. 1 through H. 3. 8, the applicant submitted two other requests for relief that involved updating examination requirements to subsequent approved editions and addenda of Sec-tion XI.

The staff has determined that the following relief requests are acceptable and in accordance with subsequent editions of Section XI referenced by 10 CFR 50.55a(b):

Examination identification

~cate or B-G-l, B-G-2, and C-D B-K-1, C-E-1, and C-C

~coa onent Bolting Welded supports Susquehanna SSER 6

10 Appendix "H

H. 4 CONCLUSION On the basis of the foregoing, the staff has determined, pursuant to 10 CFR 50.55a(a)(2),

that certain Section XI-required preservice examinations are impractical, and compliance with the requirements would result in hardships or unusual difficulties without. a compensating increase in the level of quality and safety.

The technical evaluation has not identified any practical method by which the existing Susquehanna Unit 2 can meet all the specific preservice inspection requirements of Section XI of the ASME Code.

To require exacting compliance with Section XI would delay the startup of the plant in order to redesign a

significant number of plant systems, obtain sufficient replacement components, install the new components, and repeat the preservice examination of these components.

Examples of components that would require redesign to meet the specific preservice examination provisions are the reactor vessel, residual heat removal

pumps, and a significant number of the piping and component sup-port systems'ven after the redesign effort, complete compliance with the pre-service examination requirements probably could not be achieved.

However, the as-built structural integrity of the existing primary pressure boundary has already been established by the construction code fabrication examinations.

On the basis of its review and evaluation, the staff concludes that the public interest is not served by imposing certain provisions of Section XI of the ASME Code that have been determined to be impractical.'ursuant to 10 CFR 50.55a(a)(2),

the staff has allowed relief from these requirements, which are impractical to implement and would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

Susquehanna SSER 6

Appendix H

Table H. 1 Pressure-retaining welds that are impractical to examine (Relief Request ¹7)

Wel d identifica-tion number Code

'ategory and item number System Configuration Nature of obstruction Approximate X of scan obstructed 2P-206A,B, C-359-2-L2 2P-206B, D-359-1-2 2P-206A-359-2-L1 2P202A,B,C 0-359-1-2 CG C3. 1 CG C3. 1 CG C3. 1 CF C3. 1 Core spray Shel 1

1 ongi tudinal seam Core spray Residual heat removal Shel 1 longitudinal seam Hub flange to shell Core spray Hub flange to shell Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete 2P202A,B,C, CF 0-359-2-L2 C3. 1 2P202A,B,C, CF 0-359-2-2 C3.1 2P202A,B,C, CF 0-359 L1 C3. 1 2P202A,B,C, CF 0-359-2-3 C3.1 2P202A,B,C, CF 0-359-3-7 C3.1 2P202A,B,C; CF 0-361-2-6 C3.1 2P202A,B,C, CF 0-361-6-7 C3.1 2P-202A,B,C, CF 0-361-7-8 C3.1 Residual heat removal Residual heat removal Residual heat removal Residual heat removal Residual heat removal Residual heat removal Residual heat removal Residual heat removal Shell longitudinal seam Shel 1 cir cumferen-tial seam Shell longitudinal seam Shell to bottom head Bottom head to bearing housing Discharge elbow to bottom plate flange Discharge elbow to sleeve forging Sleeve forging to top closure plate Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Encased in 100 concrete Susquehanna SSER 6

12 Appendix H

Table H.2 Piping system welds that are impractical to examine (Relief Requests

¹8, ¹9, and ¹10)

Meld identifica-tion number Code category and item number System Configuration Nature of obstruction Approximate X 'of scan obstructed 088-221" 1-FW1 VN8-821 20-F CF C2. 1 BJ

84. 5 Pipe to valve Mrapper-100 plate Reactor core isola-tion cooling Main steam Pipe to sweep-o-let 1 Lug DBB-204-1-5A CG C2. 1 088-202-1-3A CG C2.

1'BB-202-1-5A CG C2. 1 OBB-201-1-3A CG C2. 1 Main steam Main steam V

Main steam Main steam Pipe to restraint insert Pipe to restraint insert Pipe to restraint insert Pipe to restraint insert 4 restraint 25 braces 4 restraint 25 braces 4 restraint 25 braces 4 restraint 25 braces 088-203-1-58 VNB-821 17-F CG C2. 1 BJ

84. 5 Main steam Pipe to restraint insert 4 restraint 25 braces Main steam Pipe to sweep-o-let 1 lug 088-204" 1-58 CG C2. 1 Main steam Pipe to restraint insert 4 restraint 25 braces VRR-831 10-Mi BJ

'4.5 Rec ircul a-tion Longitudinal seam Branch line 5

VRR"831 10-Li VRR-831 10-Pi VRR-831 10-Q~

DBA-201 FW34 VRR-831 2Wi BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 Recircula-tion Recircula-tion Recircula-tion Reactor water cleanup Recircula-tion Longitudinal seam Longitudinal seam Longitudinal seam Pipe to elbow Longitudinal seam Branch line 10 Rigi d restraint 35 Hanger Branch line 5

Branch line 10 VRR-831 2Wi BJ

84. 5 Recircula-tion Longitudinal seam Lugs

~Obstructed areas are located outside the required examination area (12 in. from the intersection with the edge of a circumferential weld) for subsequent inservice inspections.

Susquehanna SSER 6

13 Appendix H

Table H.2 (Continued)

Weld identifica-tion number Code category and item number System Configuration Approximate Nature of X of scan obstruction obstructed DBB-203-1-3A CG C2. 1 Main steam Pipe to restraint insert 4 restraint 13 braces DLA-202 FM19 HBB-211 3-0 BJ B4. 5 CF C2. 1 DBB-201-1-5B CG C2. 1 Main steam Pipe to restraint insert Residual heat removal Pipe to elbow Feedwater Pipe to elbow 4 restraint 13

,braces Branch line 7

Hanger weld 10 GBB-215-1-5A OBB-214-1-9A DCA-208 FM11 DLA-201 FW6 DBB-207 FM3 OBB-207 FW3 CF C2. 1 CF C2. 1 BJ B4. 5 BJ B4. 5 CF C2. 1 CF C2. 1 Res idual heat removal High-pressure coolant injection Residual heat removal Feedwater Residual'eat removal Residual heat removal Pipe to elbow Pipe to elbow Elbow to valve Pipe to valve Pipe to valve Pipe to valve Lugs Lugs Branch line 5

Melded whip 60 restraint Branch line 10 Branch line 5

DBB-219-1-lc DBB-213 FW3 CF C2. 1 CG C2. 1 Feedwater Pipe to tee Core spray Pipe to pipe Branch line 5

Branch line 5

OBB-207 FMl VBB"202-1" FW1 DBB-214-3.-

10B CF C2. 1 CG C2. 1 CG C2. 1 Residual heat removal Control

" rod drive High-pressure coolant injection Pipe to valve Pipe to reducer Pipe to flange Branch line 15 Branch line 5

Branch line 15 D8B-221 FW3 CF C2. 1 Reactor Pipe to valve core isola-tion cooling (1) Branch 18 line (2) Geometry Susquehanna SSER 6

Appendix H

Table H.2 (Continued)

Weld identifica-tion number Code category and item number System Configuration Nature of obstruction Approximate X of scan obstructed HBB"211 118 CF C2. 1 Residual Pipe to tee heat removal Plate adja-5

'ent to weld 088-221 FW2 088-217 FM2 GBB"205" 2-1A CF C2. 1 CG C2. 1 CF C.2.1 Reactor core isola-tion cooling High-pressure coolant injection Residual heat removal Tee to valve Pipe to valve (1) Branch 10 line (2) Geometry Pipe support 8

,Reducer to reducer Welded hanger 25 DLA-204 FMl VN8-821 20W VB8-202 5A BJ

84. 5 BJ

84. 5 CG C2. 1 Feedwater Pipe to valve Main steam Pipe to elbow Control rod Pipe to elbow drive Welded hanger 50 Lamination 2

Lamination 5

OCA-210 FW2 BJ

84. 5 Residual heat removal Valve to flued head Joint 30 configuration VRR"831,FWA10 VRR-831 FWA11 VRR-831 FWA13 VRR-831 FMA14 VRR-831 FWB10 VRR-831 FWB11 VRR-831 FWB13 VRR-831 FW814 VRR-831 FWA33 VRR-831 FWB33 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 Recircul a-tion Recircul a-tion Recircula-tion Recircula-tion Recircul a-tion Recircula-tion Recircula-tion Recircul a-tion Recircula-tion Recircul a-tion Sweep-o-let to riser pipe Sweep-o-let to riser pipe Sweep-o-let to riser pipe Sweep-o-let to riser pipe Sweep-o-let to riser pipe Sweep-o-let to riser pipe Sweep-o-let to riser pipe Sweep-o-let to riser pipe Tee to valve Tee to valve Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geomet)y 25 25 25 25 25 25 25 25 100 100 Susquehanna SSER 6

15 Appendix H

Tabl e H. 2 (Continued)

Meld identifica-tion number Code category and item number System Configuration Approximate Nature of I of scan obstruction obstructed VRR-831 FWA24 VRR-831 FW824 VRR-B32. FMB23 VRR-831 3-F DCA-207 FM-3 DCA-207 FW3 OLA-204 FW5 DLA"204 FM21 DLA-202 FW5 DLA-202 FW10 DBA-216 FWC14 DBA-214 FWA14 OBA-214 FW22 OBA-212 FW4 DBB-215 FW10 BJ

84. 5 BJ

84. 5 BJ

84. 5

'BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 NA NA BJ

84. 5 CF C2. 1 Recircula-tion Recircula-tion Recircula-tion Recircul a-tion Core spray Core spray Valve F032A to pipe Valve F0328 to pipe Elbow to valve Pipe to cross Valve F006A to valve F007A Valve F0068 to valve F007A Main steam (augmented)

Main steam (augmented)

Main steam (augmented)

Hain steam Elbow to branch Elbow to branch Elbow to tee Tee to tee Residual heat removal Elbow to valve Feedwater Pipe to safe end Feedwater Pipe to safe end Feedwater Pipe to safe end Feedwater Pipe to safe end Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry Part geometry 100 100 25 15 100 100 35 35 35 35 30 30 30 30 10 GBB-212 FW14 GBB-212 FW14 GBB-216 FW1 CF C2. 1 CF C2;1 CF C2. 1 Residual heat removal Residual heat removal Residual heat removal Valve F0078 to flued head Valve F007A to f1ued head Reducer to nozzle Part geometry Part geometry Part geometry 33 10 Susquehanna SSER 6

Appendix H

Table H. 2

- (Continued)

Weld identifica-tion number Code category and item number System Configuration Nature of obstruction Approximate X-of scan obstructed GBB-206 FW2 GBB-216-1" FW1 GBB-205-1" FW1 CF C2. 1 CF C2. 1 CF C2. 1 Residual heat removal Residual heat removal Residual heat removal Tee to valve Reducer to nozzle Valve to reducer Par t geometry Par t geometry Part geometry 33 15 65 DBB-203 FW2 OCA-207"1-FW5 DCA-207 FW10 OCA"202-2 FW1 OCA-209 FW2 DCA-209"2-FW2 DBA-201 FW10 OBA-202"2-FW6 DCA-210 FWB BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 BJ

84. 5 Core spray Reducer to nozzle Core spray Reducer to nozzle Part geometry Part geometry Part geometry Tee to weld-o-let Reactor water cleanup Core spray Flued head to valve Part geometry Flued head to valve Part geometry Flued head to valve Part geometry Core spray Reactor water cleanup High-pressure coolant injection Residual heat removal F'lued head to valve Part geometry Elbow to valve Part geometry Feedwater Flued head to valve,Part geometry 25 20 15 60 50 50 20 18 10 OCA-211"3-FW12 BJ

84. 5 Residual heat removal Elbow to flange Part geometry GBB-201 FW1 GBB-204 FW15 CG C2. 1 CF C2. 1 Core spray Pipe to valve Residua'l Pipe to flange heat removal Part geometry Part geometry 10 Susquehanna SSER 6

17 Appendix H

Tabl e H. 2 (Continued)

Meld identifica-tion number Code category and item number System Configuration Nature of obstruction Approximate X of scan obstructed EBB-202 FW4 CG C2. 1 088-222"1" 38 NA OCA-211"3"2A BJ

84. 5 EBB-202 CG FM5 C2. 1 High-pressure coolant injecti on High-Pipe to flange pressure coolant injection Reactor Tee to flange water cleanup (augmented)

Residual Pipe to flange heat removal Part 8

geometry Part geometry Part geometry 10 Part 20 geometry HBB-218"2-CG FM5 C2. 1 HBB-201-1" CG FM3 C2. 1 Containment Pipe to valve atmosphere control Reactor Pipe to valve core isola-tion cooling Part geometry Part geometry 13 13 HBB-201"1-CG FW10 C2. 1 GBB-205 CF FW3 C2. 1 Reactor core isola-tion cooling Residual heat removal Pipe to valve Pipe to valve Part geometry Part geometry 10 10 HBB-211-2" CF FW14 C2. 1 Residual Valve to elbow heat removal Par t geometry 10 HBB-201 CG FW4 C1. 2 2P-206-A, CG B,C,D-C2.1 361"4-6 Reactor core isola-tion cooling Core spray Elbow to nozzle (pump)

Part geometry Flued head to valve Part geometry 10 10 2P"202-A, CF B,C,D-C2. 1 361-4-6 2P"202-A, CF B,C,O-C2. 1 361-1-5 Residual heat removal (pump)

Residual heat removal (pump)

Elbow to nozzl e Support shell to head hub Par t geometry Part geometry 30 10 Susquehanna SSER 6

18.

Appendix H

Table H. 2 (Continued)

Weld identifica-tion number Code category and item number System Configuration Nature of obstruction Approximate X of scan obstructed 2P-202-A, B,C,D" 361"5-13 CF C2. 1 2P-202-A, CF B,C,D-

2. 1 361-3-13 2P-202-A, CF B,C,O-C2. 1 361-5"6 2P-.206-A, CG B,C,D-'2. 1 361-5-13 2P-206-A, CF B,C,D-C2. 1 361-5-6 Residual heat

'emoval (pump)

Residual heat removal (pump)

Residual heat removal (pump)

Core spray (pump)

Core spray (pump)

Nozzle to vertical support shel.1 Fl ange to nozzl e Elbow to vertical support shell Inlet nozzle to vertical support shell Elbow to vertical support shell Part geometry Part geometry Part geometry Par t geometry Part geometry 10 10 10 10 10 GBB-201 FW2 GBB-204 FW7 CG C2. 1 CF C2. 1 Residual heat removal Valve to pipe Core spray Valve to pipe Part geometry Part geometry 25 OBB-215 CF FW7 C2. 1 OLA-202-1 BJ FW6 B4.5 Residual heat removal Feedwater Valve to pipe Pipe to tee Part geometry Part geometry 15

~

Susquehanna SSER 6

19 Appendix H

Table H.3 Pressure-retaining welds that are impractical to examine (Relief Request ¹ll)

Weld identi fica-tion number Code category and item number System Configuration Nature of obstruction Approximate X of scan obstructed 2E-205-A-R CA Residual Cl. 1 heat removal Shell to head Welded 5

attachment 2E-205-A-A CB C1. 2 Residual heat removal Shell to nozzle Adjacent weld 20 2E-205-A-AC CA C1. 1 Residual heat removal Shell to flange Outlet nozzle 20 2E-205 R CA C1. 1 2E-205"8-A CB C1. 2 2E-205"8-AC CA C1. 1 2E-205-A-P CB C1. 2 2E-205"8-P CB C1. 2 Residual heat removal Residual heat removal Residual heat removal Residual heat removal Residual heat removal Shell to head Shel 1 to nozzle Shell to flange Shell to nozzle Shell to nozzle Welded attachment Adjacent weld Outlet nozzle Adjacent weld-o-. let Adjacent weld-o-let 20 20 Susquehanna SSER 6

20 Appendix. H

U.S. NUCLEAR REGULATORY COMMISSION BIBLIOGRAPHICDATASHEET

4. TITLE AND SUBTITLE (Add Volume No.,ifapproprlateJ Safety Evaluation Report related to the operation of Susquehanna Steam Electric Station, Units 1 and 2.

Docket Nos.

50-387 and 50-388.

7. AUTHORIS)

9. PERFORMING ORGANIZATION NAME AND MAILINGADDRESS (Include Zip CodeJ Division of Licensing Office of Nuclear Reactor Regulation U". S.

Nuclear Regulatory Commission Washington, D. C. 20555

'12. SPONSORING ORGANIZATION NAME AND MAILINGADDRESS (Include Zip CodeJ Same as 9

above.

3. RECIPIENT'S ACCESSION NO.

5. DATE REPORT COMPLETED YEAR MONTH March 1984 DATE REPORT ISSUED MONTH YEAR

8. (Leave blankJ

8. (Leave blankJ IO. PROJECT/TASK/WORK UNIT NO.

11. FIN No.

1. REPORT NUMBER (Assipned by DDCJ NUREG-0776 Su lenent No.

6

2. (Leave blank J

13. TYPE OF REPORT Technical

15. SUPPLEMENTARY NOTES PERIOD COVERED (Inclusive datesJ March 1983 - March 1984

14. (Leave blankJ

16. ABSTRACT (200 words or less J In April 1981, the staff of the Nuclear Regulatory Commission issued its Safety Evaluation Report (NUREG-0776) regarding the application of the Pennsylvania Power and Light Company (applicant or licensee) and the Allegheny Electric Cooperative, Inc.

(co-applicant) for licenses to operate the Susquehanna Steam Electric Station, Units 1

and 2, located on a site in Luzerne County, Pennsylvania.

t Supplements 1 and 2 were issued in June 1981 and September 1981, respectively and addressed several outstanding issues.

Supplement No.

2 also contains NRC staff responses to the comments made by the Advisory Committee on Reactor Safeguards in its report, dated August ll, 1981.

Supplement 3 was issued in July 1982 and addressed five items that remained open and closed them out.

On July 17, 1982, Operating License NPF-14 was issued to allow Unit 1 operation at power levels not to exceed 5% of rated power.

Supplement 4 was issued November 1982 and discusses the resolution of several license conditions.

On November 12, 1982, Operating License NPF-14 was amended to remove the 5X power restriction, thereby permitting full-'power operation of Unit 1..

Supplement 5 and this Supplement, No. 6,addresses several issues

17. KEY WORDS AND DOCUMENT ANALYSIS I 7a, DE SC R IPTORS 17b. IDENTIFIERSIOPEN ENDED TERMS

18. AVAILABILITYSTATEMENT NRC FORM 335 (11.81)

Unlimited 19, NCURQYf/'lmtrepOrtl

"%K%ESTPfEd"""

21. NO. OF PAGES

22. PRICE S

V

'/9l -~~ - 4'39'2 l4 >3