ML17214A142

Safety Evaluation Report Related to the Operation of St. Lucie Plant,Unit No. 2.Docket No. 50-389.(Florida Power and Light Company,And Orlando Utilities Commission of the City of Orlando,Florida)

ML17214A142
Person / Time
Site:	Saint Lucie
Issue date:	09/30/1982
From:	Office of Nuclear Reactor Regulation
To:
References
NUREG-0843, NUREG-0843-S02, NUREG-843, NUREG-843-S2, NUDOCS 8306010057
Download: ML17214A142 (81)

Text

NUREG-0843 Supplement No. 2

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rellated to the ope~atio~ of St. Lvcie Pliant, Unit Mo. 2 Docket No. 50-389 Florida Power and Light Company Orlando Utilities Commission of the City of Orlando, Florida U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation September 1982 NOTICE THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE DIVISION OF DOCUMENT CONTROL.

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FROM DOCUMENT FOR REPRODUCTION MUST BE REFERRED TO FILE PERSONNEL.

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)fp*y4 DEADI1NE RETURN DATE RECORDS FACILITYBRANCH

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1.

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NUREG-0843 Supplement No. 2 Ssfety Ev Report related to the operation of St. Lucie Plant, Unit No. 2 Docket No. 50-389 Florida Power and Light Company Orlando Utilities Commission of the City of Orlando, Florida U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation September 1982

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TABLE OF CONTENTS 1

INTRODUCTION AND GENERAL DISCUSSION

l. 1 Introduction 1.7 Summary of Outstanding Issues 1.8 Confirmatory Issues 1.9 License Conditions 1.10 Generic Issues 2

SITE CHARACTERISTICS

2. 1 Geography and Demography

2. 1.3 Population Distribution 2.3 Meteorology

'2.3. 1 Regional Climatology 2.5 Geology and Seismology 2.5.3 Surface Faulting 2.6 References 3

DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3.4 Water Level (Flood) Design 3.4. 1 General Discussion 3.5 Missile Protection 3.5.3 Barrier Design Procedures 3.9 Mechanical Systems and Components 3.9. 2 Dynamic Testing and Analysis of Systems, Components, and Equipment 3.9.6 Inservice Testing of Pumps and Valves 3.10 Seismic and Dynamic qualification of Seismic Category I Mechani ca 1 and El ectr ical Equipment 3.10.1 Seismic and Dynamic qualification 3.10.2 Operability qualification of Pumps and Valves

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l-l 1-2 1"3 1-4 2-1 2-1 2-1 2-1 2-1 2-1 2-1 2-2 3-1 3-1 3-1 3-1 3-1 3-2 3-2 3-2 3-2 3-2 3-3 St.

Lucie SSER 2

4 REACTOR TABLE OF CONTENTS (Continued)

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4.2 Fuel System Design 4.2. 1 Design Basis 4.2.3 Design Evaluation

4. 4 Thermal-Hydraul i c Desi gn 4.4.5 Analog Core Protection Calculator 6

ENGINEERED SAFETY FEATURES 6 '

Emergency Core Cooling System 6.3.2 Evaluation 7

INSTRUMENTATION AND CONTROLS 7.3 Engineered Safety Features Actuation System 7.3.3 Auxiliary Feedwater System 7.3.6 Containment Isolation 7.5 Safety-Related Display Instrumentation 7.5.4 Postaccident Monitoring Instrumentation 4-1 4-1 4-1 4-2 4-2 6-1 6-1 6-1 7-1 7-1 7-1 7-1 7-2 7-2 9

AUXILIARYSYSTEMS

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9-1 9.5 Other Auxiliary Systems 9.5. 1 Fire Protection 10 STEAM AND POWER CONVERSION SYSTEM 10.4 Other Features of the Steam and Power Conversion System 10.4.9 Auxiliary (Emergency)

Feedwater System 13 CONDUCT OF OPERATIONS

13. 1 Introduction

13. 1. 1 Management and Technical Support Organization 13.3 Emergency Planning 13.3.1 Introduction 13.3.2 Evaluation of the Emergency Plan 9-1 10-1

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Lucie SSER 2

iv

13. 3. 3

13. 3. 4

13. 3. 5 TABLE OF CONTENTS (Continued)

Review and Evaluation of State and Local Plans by F EMA e

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NRC Review of the State of Florida DOT Analysis of Hutchinson Island Traffic.

Conclusions

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13-7 13-8 13-8 13.5 Plant Procedures 13.5. 1 Administrative Procedures 13.6 Physical Security Plan 15 ACCIDENT ANALYSIS 15.5 Reactor Coolant Pump Shaft Seizure and

15. 10 Limiting Accidents Shaft Break 13-9 13-9 13-9 15-1 15-1 15-1

15. 10.6 Anticipated Transients Without Scram 16 TECHNICAL SPECIFICATIONS 17 QUALITY ASSURANCE 17.2 Organization

,17.3 Quality Assurance Program 20 FINANCIAL QUALIFICATIONS.

22 TMI-2 REQUIREMENTS 22.2 Discussion of Requirements 15-1 16-1 17-1 17-1 17-1 20-1 22-1 22-1 St.

Luci e SSER 2

TABLE OF CONTENTS (Continued)

APPENDICES A

CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL REVIEW.

B ERRATA TO SAFETY EVALUATION REPORT (SER)

AND SUPPLEMENT 1 TO THE C

NRC UNRESOLVED SAFETY ISSUES D

SEISMIC AND DYNAMIC QUALIFICATION OF SEISMIC CATEGORY I MECHANICAL AND ELECTRICAL E(UIPMENT AUDIT REPORT.

E REVIEW AND EVALUATION OF STATE AND LOCAL PLANS BY FEMA F

PRINCIPAL CONTRIBUTORS

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B-1 C-1 D-1 E-1 F-1 St.

Lucie SSER 2

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TABLE OF CONTENTS (Continued)

LIST OF FIGURES 13.1 Florida Power and Light Co.

major organizational reporting to Executive Vice President.

13.2 Florida Power and Light Co. major organizational Nuclear Energy 13.3 Florida Power and Light Co. major organizational Power Resources.

17. 1 FP8L Organization - Operations gA.

components

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components of Pacae 13-11 13-12 13-13 17-2 St.

Lucie SSER 2

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1 INTRODUCTION AND GENERAL DISCUSSION

1. 1 Introduction On October 9, 1981, the Nuclear Regulatory Commission (NRC) staff issued a

safety evaluation report (SER) related to the operation of St.

Lucie Plant Unit 2.

Supplement No.

1 (SSER 1) to the SER was issued in December, 1981.

In the SER and SSER 1 the staff identified certain issues where either further information or additional staff effort was necessary to complete the review.

The purpose of this supplement is to update the SER by providing (1) our evaluation of additional information submitted by the applicant since SSER 1

to the SER was issued and (2) our evaluation of the matters the staff had under review when the SSER 1 was issued.

Each of the following sections of this supplement is numbered the same as the section of the SER and SSER 1 that is being updated, and unless otherwise

noted, the discussions are supplementary to and not in lieu of the discussion in the SER and SSER 1.

Appendix A to this supplement is a continuation of the chronology.

Appendix 8 is the errata to the Safety Evaluation Report (SER) and Supplement 1 to the SER.

Appendix C is NRC unresolved safety issues.

Appendix D is the seismic and dynamic qualification of seismic Category I mechanical and electrical equipment audit report.

Appendix E is the review and evaluation report of state and local plans by FEMA.

Appendix F is the list of principal contributors to the staff review.

1.7 Summar of Outstandin Issues Section 1.7 of the SER contained a list of outstanding issues.

This supplement addresses the resolution of a number of these issues previously identified as open.

These are listed below, along with the section of this report wherein their resolution is discussed.

(1)

Seismic and LOCA loads (4.2.3.3d) becomes confirmatory (2)

Emergency Planning (13.3) become a license condition (3)

ATHS Procedures (15.10.6)

(4)

TMI Issues (Emergency Operating Procedures (I.C.1., I.C.8)).

At this time, there rema'in a number of safety issues that have not yet been resolved.

These will be addressed in a subsequent supplement to the SER.

The following is a list of these items.

(1)

Seismic qualification (3. 10. 1)

(2)

Pump and Valve Operability Assurance (3. 10.2)

(3)

Environmental qualifications (3. 11)

(4)

Fuel Handling System Light Loads (9. 1.4)

(5)

Fire Protection (9.5. 1)

St.

Lucie SSER 82

l. 8 Confirmator Issues At the time of the SER issuance there were several issues which were essentially resolved to the staff's satisfaction, but for which certain confirmatory infor-mation had not yet been provided by the applicant.

Since that time, the staff has reviewed this information and, as expected, has confirmed the preliminary conclusions.

These issues are listed below with appropriate references to sub-sections of this report.

(1)

Surface faulting (marine seismic reflection survey) (2.5.3)

(2)

Dynamic. analysis of reactor internals (3.9.2.2)

(3)

Inservice testing of pumps and valves (3.9.6)

(4)

Fuel rod mechanical fracturing (4.2. 1.2(g))

(5)

Analog core protection calculator (4.4.5)

(6)

Fire Protection (9.5. 1) becomes an outstanding issue (7)

Reactor coolant pump shaft seizure and shaft break (15.5)

(8)

Emergency Operating Procedures (I. C. 7)

(9)

Thermal Mechanical Report (II.K.2.13)

(10)

Potential for voiding in the RCS during transients (II.K.2. 17)

(ll)

Revised small-break LOCA methods (II.K.3.30)

For a number of confirmatory issues, the remaining act'ion involves verification by the NRC staff that the applicant has implemented its acceptable commitments with regard to such items as equipment installation or modification, alarms or setpoints, and plant procedures'or testing.

The following confirmatory issues are included in this verification category.

(1)

Preoperational flow-induced vibration testing of reactor internals (3.9.2.3)

(2)

Logic matrix and logic matrix power supplies (7.2.5)

(3)

Containment isolation (7.3.6)

(4)

Shutdown Cooling System (7.4.4)

(5)

Inadvertent boron dilution event (15.6.3)

(6)

Emergency Operating Procedures (I.C.7 and I.C.8)

Verification of the above. items will be accomplished as part of the ongoing inspection program for St.

Lucie 2 conducted by the Region II Office of NRC.

The NRC inspection staff will assure that these items are completed prior to fuel loading.

At this time several issues remain for which the staff has not yet received the

--- necessary confirmatory information.

These issues, which are listed below, will be addressed in a subsequent supplement to the SER.

(1)

Other Category I structures (Masonry Mails) (3.8.4)

(2)

Piping load. combinations and stress limits (3.9.3. 1)

(3)

Intersystem LOCA (3.9.6)

(4)

Design stress,

strain, and strain fatigue on fuel system (4.2.3.1(a, b,

and c))

(5)

CEA axial growth and fretting,(4.2.3. 1(d and g).)

(6)

Rod pressure (4.2.3. 1(h))

(7)

Fuel rod mechanical fracturing (4.2.3.2(g))

(8)

Seismic and LOCA loads (4.2.3.3(d))

St.

Lucie SSER ¹2 1-2

(9)

(10)

(11)

(12)

(13)

(14)

(15)

(16)

(17)

(18)

(19)

(20)

Loose parts monitoring (4.4.4)

Preservice inspection results of reactor vessel (5.2.4)

Relief request from ASME preservice inspection program for Class 1,

2 and 3 and from preservice inspection of the reactor vessel (5.2.4 and 6.6)

Boron mixing test results (5. 4.3)

Natural circulation cooldown tests (5.4.3)

Upper head voiding (5.4.3)

Sump vortex test (6.3.3)

Provide analysis confirming that start-up channel flux alarm setpoints demonstrate sufficient operator war ning time (15. 6. 3)

Feedwater system pipe breaks (15. 10.2)

Inadvertent opening of PORV (15. 10.5)

Steam generator tube failure (with and without AC) (15. 10.4)

Control Room Design Review (I.D. 1) 1.9 License Conditions Section 1.9 of the SER contained a list of license conditions.

This supplement addresses the resolution of one of these conditions.

This is listed below, along with the section of this report wherein the resolution is discussed.

(1)

(2)

Barrier design procedures (3.5.3)

Postaccident monitoring instrumentation (7.5.4)

The list below provides the number of license conditions at this time:

(1)

Population Distribution (2. 1.3)

(2)

Structural modifications due to ductibility factor reanalysis results (3.5.3)

(3)

Fragmentation of embrittled cladding (4.2.3.3(a))

(4)

Inservice Inspection Program for Class 1,

2 and 3 (5.2.4 and 6.6)

(5)

Low flow alarms on safety injection pumps (5.4.3)

(6)

Potential replacement of existing sequencing relays with electronic timing relays (8.3.1.1)

(7)

Non-safety loads on emergency power sources (8. 4. 2)

(8)

Containment electrical penetr ations (8.4.3)

(9)

Second fuel pool heat exchanger (9. 1.3)

(10) -Sound powered telephone system (9.5.2.1.0)

(ll) Emergency. diesel engine auxiliary support systems (9.5.4. 1)

(12) Diesel generator tube oil modifications (9.5.7)

(13) Turbine disc integrity (10.2.1)

(14) Secondary water chemistry (10.3.4)

(15) Mater hammer testing (10.4.7)

(16) Waste management system concentrator bottom tanks (11.2)

(17) Refueling water storage tank level indication (11.2)

(18) Air-operated fail-closed automatic block valves (11.2)

(19) Process Control Program for wet radioactive solid waste (11.4)

(20) Emergency Planning (13.3)

(21) Safety parameter display system (I.D.2)

(22) Reactor coolant system vents (II.B.1)

(23) Postaccident sampling capability (Section 22, II.B.3)

(24) Inadequate Core Cooling Instrumentation (Section 22, II.F.2)

St.

Lucie SSER 82 1-3

1.10 Generic Issues NRC continuously evaluates the safety requirements used in its review against new information as it becomes available.

In some cases, the staff takes immedi-ate action or interim measures to assure safety.

In most cases,

however, the initial assessment indicates that immediate licensing actions or changes in licensing criteria are not necessary.

In any event, further study may be deemed appropriate to make judgments as to whether existing requirements should be modified.

These issues being studied are sometimes called generic safety issues because they are related to a particular class or type of nuclear facility.

A discussion of NRC's program to resolve a generic issue that has been defined since the SER and SSER 1 was issued is presented in Appendix C to this report.

,St.

Lucie SSER 82

2 SITE CHARACTERISTICS

2. 1 Geo ra h

and Demo ra h

2. 1. 3 POPULATION DISTRIBUTION In the Safety Evaluation Report (NUREG-0843),

we stated that because of projected growth and expansion of the city of Port St.

Lucie, we would require the applicant to amend the FSAR so the Port St.

Lucie would be designated as the nearest popu-lated center instead of Ft. Pierce.

On August 9, 1982, the applicant submitted Amendment 12 to the FSAR which states that if Port St.

Lucie continues to grow, the population should exceed 25,000 by 1995 at which time it would become the nearest most densely populated center.

Since both Ft. Pierce and Port St.

Lucie are at least one and one-third times the distance from the site to the LPZ outer radius, we conclude that they meet the requirements of 10 CFR Part 100.

2.3. 1 Regional Climatology In Section

2. 3. 1 of the SER, the staff stated that the applicant agreed to amend the FSAR to reflect conformance with the guidelines of Regulatory Guide 1.76 design basis tornado characteristics.

In Amendments ¹7 and ¹10 to Section

3. 3. 2

("Tornado Loadings") of the FSAR, the applicant has confirmed that the character-istics of the design basis tornado for St.

Lucie 2 are equivalent to those pre-sented in Regulatory Guide 1.76 for this region of the country.

This completes action on an agreement by the applicant'Letter ¹L-81-381, Uhrig to Eisenhut) to amend the FSAR on this subject.

2.5 Geolo and Seismolo 2.5.3 Surface Faulting In a recent Master Thesis (Armstrong, 1980) (Ref 1),

a fault had been postulated to exist beneath south Hutchinson Island approximately 7.2 km (4.5 mi) south of the site.

The applicant had presented results (Ref.

2 and 3) of seismic r'eflection profiles to prove that the postulated fault was really a fold.

However, as discussed in Section 2.5.3 of the SER, the staff found that the quality of the sections provided was inadequate to support the applicant's conclusion.

The staff empha-sized that the significant amount of ringing in the sections limited the inter-pretation and as a result the staff requested that the data be reprocessed.

In March 1982 (Ref 4) the applicant provided the staff with the processed data.

The sequence of reprocessing the data was editing, scaling, mixing, and then decon-volution.

The reprocessed data was of more reasonable quality than the original data provided and some of the ringing was eliminated.

The staff reviewed the reprocessed data and our interpretation of the data agrees with those of the appli-cant (Ref. 5).

Our analysis confirms that the anomaly in the site area is a St.

Lucie SSER ¹2 2-1

fold and not a fault.

In the SER, it was concluded that "based on our review of the FSAR and the scientific literature, a preliminary. review of the seismic reflection data, the relatively low historic seismicity in the southern Atlantic Coastal

Plain, and the absence of any evidence of recent fault movement in eastern United States, it is our position that the postulated fault is not capable by the standards set forth in Appendix A, 10 CFR Part 100."

Our conclusion remains that there are no geologic features in the site vicinity representing a hazard or potential hazard to the St.

Lucie. Plant.

2.6 References l.

Armstrong, J.

R., 1980.

The Geology of the Floridian aquifer system in eastern Martin and St.

Lucie Counties, Florida:

Unpublished Master's Thesis, The Florida State University.

2.

Florida Power and Light Company, 1980, Final Safety Analysis Report, St.

Lucie Plant, Unit No. 2; Docket No. 50-389.

3.

Florida Power and Light Company, 1981, Lette~ from R.

E. Uhrig to D. Eisenhut-responses to requests for additional information; August 4, 1981.

Law Engineering Testing

Company, 1982, Letter from Law Engineering Testing Company to Ebasco Services, Inc., Transmittal of Marine Seismic Reflection Data; March 19, 1982.

5.

Florida Power and Light Company, 1982, Letter from R.

E. Uhrig to D. Eisenhut, Marine Seismic Investigation - Interpretation of Processed Data; July 15, 1982.

e St.

Lucie SSER 82 2-2

3 DESIGN CRITERIA-STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3.4 Water Level Flood Desi n

3. 4. 1 General Discussion In the SER input we stated that the probable maximum surge from the probable maximum hurricane not including the wave runup, is 16.7 feet MSL.

This is the elevation obtained from Regulatory Guide 1.59 as applied to St.

Lucie.

The applicant in Amendment 6 has taken a more conservative position by using a high water level of 17.2 feet MSL.

We conclude that the use of a, water level which is higher than is specific in Regulatory Guide 1.59 is acceptable.

3.5 Missile Protection 3.5.3 Barrier Design Procedures The St.

Lucie Unit 2 steel structures that are required to resist missile pene-tration were designed using a ductility factor larger than allowed by the staff.

These structures were reanalyzed using the lower ductility factor and it was found some of the structures would have to be strengthened.

The major structures that required strengthening have been reworked.

The items remaining are small and consist of the following three items.

(1)

Intake Structure Pump enclosure fan housing (2)

Condensate Storage Tank vent hood housing (3)

Reactor Auxiliary Building sliding door The structure involved in items 1 and 2 are some framing members located inside the housings themselves.

The items are located on the roofs of the referenced structure.

The maximum allowed ductility ratio is 10, whereas the ductility ratio computed is a maximum of 3.6.

This would mean that some permanent deforma-tion of the members involved may occur if they were impacted by the postulated tornado missile but the missiles are not expected to enter the structure.

Since the housings are expected to prevent the tornado missile from entering the structure, the staff concludes that accomplishing the strengthening by the first refueling is acceptable.

The Reactor Auxiliary Building (RAB) sliding door support beam is a newly identified barrier that was not on the original list and was discovered during later reanalysis.

This door support beam is located in a wall, that faces East and above El 62.00 (roof of the RAB).

This wall is the outer perimeter of the Control Room section of the RAB and closes off a room that contains HVAC Fans 5A and 5B.

The critical missile direction is vertical and if this missile impacted the door support

beam, some damage to the beam may result;

however, the door itself should not be damaged.

Since the door should not be damaged, the staff concludes that accomplishing the strengthening of the door support beam by the first refueling is acceptable.

St.

Lucie SSER 82 3-1

3.9 Mechanical S stems and Com onents 3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment

3. 9. 2. 2 Dynamic Analysis of Reactor Internals In Section

3. 9. 2. 2 of the St.

Lucie Unit No.

2 SER, we stated that the applicant's analysis of the primary coolant system for asymmetric LOCA loads was in progress using criteria which we considered acceptable.

Me fur ther stated that we would review the final results of these analyses to assure that the commitments upon which our approval was based had been met.

In Section 3.9.5.4 of Amendment 9

to the FSAR, the applicant discussed the results of these analyses.

Me have reviewed this information and have determined that these results provide an adequate basis for us to conclude that our evaluation of this subject in Section 3.9.2.2 of the SER is still valid and that the applicant's analysis constitutes an acceptable basis for complying with'tandard Review Plan Section 3.9.2 and for satisfying the applicable requirements of General Design Criteria 2 and 4.

3.9.3.2 Pump and Valve Operability Assurance At the time the applicant's pump and valve operability assurance program was being reviewed by the staff and the results of the review written up in the SER, the review was under Standard Review Plan (SRP) Section 3.9.3.

Since then the pump and valve operability assurance (now known as "Operability gualification of Pumps and Valves" ) is reviewed under NUREG-0800 (SRP Section

3. 10).

Furth'er-more, discussion of this subject is now under'ection

3. 10.2, "Operability gualification of Pumps and Valves," of this SSER and future SSERs.

3.9.6 Inservice Testing of Pumps and Valves In Section 1.8 of the SER and SSER 1, item (6) lists inservice testing of pumps and values (3.9.6) as a confirmatory item.

This item should not have been listed since FPAL has submitted information on their proposed inservice testing of pumps and valves.

Subsequent to the staff review of the submitted information, the staff granted relief from the requirement of 10 CFR 50, Sections 50.55(g)(2) and (g)(4)(i) for that protion of the initial 120-month period during which the staff will complete their review.

The staff finds that the relief granted will not endanger life or property and it is in the public interest.

3. 10 Seismic and D namic uglification of Seismic Cate or I Mechanical and Electrical E ui ment

3. 10. 1 Seismic and Dynamic gualification Our evaluation of the adequacy of the applicant's program for qualification of safety-related electrical and mechanical equipment for seismic and dynamic loads consists of (1) a determination of the acceptability of the procedures

used, standards followed, and the completeness of the program in general, and (2) an on-site audit of selected equipment items to develop the basis for the staff judgement on the completeness and adequacy of the implementation of the entire seismic and dynamic qua'lification program.

St.

Luci e SSER 82 3-2

The Seismic Qualification Review Team (SQRT) has reviewed the equipment dynamic qualification information contained in the pertinent. Final Safety Evaluation Report (FSAR) Sections 3.9.2 and 3. 10 and made a site visit on May ll through May 14, 1982 to determine the extent to which the qualification of equipment as installed in St.

Lucie 2, meets the current licensing criteria -as described in IEEE 344-1975, Regulatory Guides 1.92 and l. 100, and the Standard Review Plan Sections 3.9.2 and 3. 10.

Conformance with these criteria satisfies the applicable portions of General Design Criteria in 1, 2, 4, 14, 18 and 30 of Appendix A to 10 CFR Part 50, as well as Appendix B to 10 CFR Part 50 and Appen-dix A to 10 CFR Part 100.

A representative sample of Seismic Category I mechani-cal and electrical equipment, as well as instrumentation, includes in both NSSS and BOP scopes, were selected for the plant site review.

The review consisted of field observations of the actual equipment configuration and its installation, followed by the review of the corresponding test and/or analysis documents.

In instances where components have been qualified by test or analysis to other than current licensing criteria such as IEEE Standard 344-1975, Regulatory Guides 1.92 and 1. 100, and the Standard Review Plan Sections 3.9.2 and 3. 10, the applicant has undertaken a re-evaluation and requalification program.

Based on the SQRT audit findings as discussed with the applicant during the exit meeting, we concluded that in order to complete our review, we would require the applicant to provide additional information and-to clarify the details of the qualification for some pieces of equipment.

In response to these

concerns, the applicant provided a post-audit submittal on June 17, 1982.

A number of concerns had since been resolved during several conference calls between the SQRT and the applicant.

Our remaining concerns are summarized in the audit report in Appendix D.

The applicant also informally submitted a document on August 16, 1982, which is in response to several of the open items identi-fied in the audit.

This latter document is being reviewed while we wait for the formal submittal.

3. 10.2 Operability Qualification of Pumps and Valves To assure the applicant has provided an adequate program for qualifying safety-related pumps and valves to operate under normal and accident conditions the Equipment Qualification Branch (EQB) performs a two-step review.

The first step is a review of Section 3.9.3. 2 of the FSAR for the description of the applicant's pump and valve operability assurance program.

This information is compared to Section

3. 10 of the Standard Review Plan.

The information provided in the

FSAR, however, is general in nature and not sufficient by itself to provide confidence in the adequacy of the licensee's overall program for pump and valve operability qualification.

To provide this confidence, the Pump and Valve Operability Review Team (PVORT), in addition to reviewing the FSAR, conducts an on-site audit of a small representative sample of safety-related pumps and valves supporting documentation.

The on-site audit includes a plant inspection to observe the as-built configura-tion and installation of the equipment, a discussion of the system in which the pump or valve is located and of the normal accident conditions under which the component must operate, and a review of the qualification documentation (stress reports, test reports, etc.)

St.

Lucie SSER ¹2 3-3

The two-step review is performed to determine the extent to which the qualifica-tion of equipment, as installed, meets the current licensing criteria as described in the Standard Review Plan 3. 10.

Conformance with these criteria satisfies the applicable portions of General Design Criteria 1, 2, 4, 14, 18 and 30 of Appendix A to 10 CFR Part 50, as well as Appendix B to 10 CFR Part 50.

The on-site audit for St.

Lucie, Unit 2 was performed May 11-14, 1982.

A repre-sentative sample consisting of 8 valves and 3 pumps was chosen for review.

-The sample included both NSSS and BOP equipment.

During our review a number of concerns were raised.

Some of these concerns were satisfactorily resolved by the applicant during the audit by either supplying additional information or providing additional commitments as appropriate.

The remaining concerns are summarized in the audit report in Appendix D.

The applicant also informally submitted a document on August 16, 1982, which is in response to several of the open items identified in the audit.

This latter document is being reviewed while we wait for the formal submittal.

St.

Lucie SSER 02 3-4

4 REACTOR 4.2 Fuel S stem Desi n

4.2. 1 Design Bases 4.2. 1.2 (g)

Design Basis for Mechanical Fracturing Mechanical fracturing of a fuel rod could potentially arise from an externally applied force, such as a hydraulic load, or a load derived from core-plate motion.

Stress limits to preclude such failure were not provided in the original FSAR and this design basis for mechanical fracturing was thus described as an unresolved issue.

The applicant has stated in Amendment 10 to the FSAR that fuel rod fracture stress limits shall be in accordance with the criteria given in Table 9-1 of the Combustion Engineering generic topical report, CENPD-178, Revision 1 ("Structural Analysis of Fuel Assemblies for Seismic and Loss-of-Coolant Accident Loading," August 1981).

The review of CENPD-178, Revision 1 and the criteria given in Table 9-1 have

, recently been completed and found acceptable (L.

S.

Rubenstein memorandum for R.

L. Tedesco, "Safety Evaluation of CE Seismic and LOCA Loads Analysis,"

June 17, 1982).

Consequently, the design basis and limit for fuel rod mechanical fracturing are acceptable and thus resolved.

4.2.3.

Design Evaluation 4.2.3.2 (g)

Analysis for Mechanical Fracturing In Amendment 10, FPL has stated, that previous analyses (such as for the San Onofre plants) have shown that the limiting cladding stress conditions from externally applied forces would occur during a seismic and LOCA (SKL) event.

Therefore, if fuel rod mechanical performance during a S&L event is found to be acceptable, then by deduction, fuel rod mechanical fracture due to other events would not be expected.

We conclude that this inference is reasonable.

However, since we have not received the final SKL analysis for St.

Lucie, Unit 2, we are unable to resolve this issue and will report on its resolution in a later SSER following our approval of the SRL analysis.

4.2.3.3(d)

Seismic and LOCA Loads In the SER, the analysis for structural damage from external forces had not been reviewed because the applicant had not completed it.

Since then we have received a preliminary report that provided numerical results of an S8 L analysis that used methods described in CENPD-178.

We have recently completed our review of "Revision 1 to CENPD-178 and approved those methods as submitted.

Therefore, we anticipated that the final analysis will demonstrate acceptable

results, and we believe that the SKL analysis should be recategorized as a confirmatory issue.

St.

Lucie SSER ¹2

4.4 Thermal-H draulic Desi n

4.4.5 Analog Core Protection Calculator In Section 1.8 of Supplement 1 to the

SER, item (12) lists analog core protection calculator as a confirmatory item.

This item should not have been listed here because it was part of the Technical Specification (TS).

Therefore, verification of this item will be accomplished as part of the ongoing TS proof and review effort.

The NRC staff will assure this item is completed prior to fuel loading.

St.

Lucie SSER ¹2 4-2

6 ENGINEERED SAFETY FEATURES 6.3 Emer enc Core Coolin S stem 6.3.2 Evaluation With regard to the capability of the HPSI pumps to operate for extended periods of time, in Section 6.3.2 of the SER, the staff reported that the St.

Lucie 2 HPSI pumps are manufactured by the Bingham-Wi llamette Company.

These pumps are similar in design to conventional steam generator feed pumps where continuous service over a broad range of temperature is required.

In order to verify that these HPSI pumps will satisfy long-term requirements, we have required that the applicant provide a service summary of operating history for Bingham-Willamette pumps.

In Amendment 9 to the FSAR, the applicant has provided a list of pumps with similar design that has been used in other operating plants with satisfactory services.

The St.

Lucie pumps have a design life time of 40 years.

Operational testing is considered as part of the functional requirements of the pump.

For the purpose of pump specification and design, the long-term LOCA requirement is defined as continuous operation for up to one year at run out conditions.

We have reviewed the applicant submittal involving the capability of the HPSI pumps to operate for long-term cooling, and conclude that this issue is resolved.

In Section 6.3.2 of the SER, the staff reported that the applicant has confirmed that low flow alarms are being added to the LPSI and HPSI pumps for the ECCS pump protection.

These alarms will have emergency power supplies.

In a letter dated May 4, 1982, the applicant has indicated that the above-stated low flow alarms will not be installed until 12 months after core load.

This is because of the limited amount of time available to engineer and procure this equipment after agreement to install the system during the FSAR review by the NRC staff.

We have reviewd the applicant request and find this acceptable.

This conclusion is based on the following:

The low flow alarms are provided for added protection of ECCS pumps from a loss of pump suction or discharge flow path during shutdown cooling or post-LOCA long-term operation.

There are other indications available to assure ECCS pump performance during plant operation (e. g.,

HPSI and LPSI pump discharge header pressures and motor currents).

In addition, as we reported in the SER, the applicant has committed that operating procedures will be developed to period-ically check ECCS performance during the long-term cooling.

The plant operators are also being instructed in the recognition and mitigati'on of ECCS performance degradation.

In accordance with the requirements of NUREG-0737 (Item I.C. 1),

guidelines for alerting the operator to the symptoms of inadequate core cooling will be available.

Based on the preceding factors, we conclude that the applicant's proposal for later installation of the low flow alarms is acceptable.

St.

Lucie SSER ¹2 6-1

7 INSTRUMENTATION AND CONTROLS

'.3 En ineered Safet Features Actuation S stem 7.3.3 Auxiliary Feedwater System 7.3.3. 1 Auxiliary Feedwater System Automatic Initiation In the staff's Safety Evaluation Report (SER) dated October 1981, the design of the St.

Lucie 2 auxiliary feedwater system (AFWS) automatic initiation system has been found acceptable.

Subsequent to the SER, the applicant stated in their letter (R. Uhrig to D.

Eisenhut) dated May 4, 1982 that the automatic initiation circuitry will be in place by core load but the electrical tie-ins will not be complete by core load because of the heavy demand on the electrical construction trades.'he elec-trical system will be the only portion of the AFWS which will not be complete.

The applicant has committed to have the automatic initiation system completely installed and fully operational before exceeding 5/o power.

Also, additional information has b'een provided in the May 4, 1982 letter justifying the opera-tion of the reactor up to 5X power without the automatic initiation function.

The auxiliary feedwater pumps will be operating-continuously to provide makeup to the steam generators while the plant is in a low power condition ((5X) and therefore, emergency initiation of the auxiliary feedwater system wilT not be required since the auxiliary feedwater pumps will be operating up to the 5/o power range.

The main feedwater pumps are not used at low power conditions.

Based on the above justification and commitment by the applicant, we conclude that the automatic initiation portion of the AFWS need not be "completely in-stalled and fully operational prior to operation of the reactor up to the 5X power range.

However the applicant will be required to formally confirm completion (complete installation and full operability) of the auxiliary feed-water automatic initiation function prior to plant operation above 5X power.

7..3.6 Containment Isolation In the St.

Lucie 2 Safety Evaluation Report (SER) dated October 9, 1981, we expressed a concern about insufficient.diversity for the containment isolation actuation signal (CIAS).

As a result, the applicant committed to modify the St.

Lucie 2 containment isolation system design so that the CIAS will be ini-tiated on a safety injection actuation signal (SIAS) as well as on high con-tainment pressure or high containment radiation.

In Amendment No.

6 to the St.

Lucie 2 FSAR, the applicant revised Section 7.3. 1. 1.4 and FSAR Figure 7.3-4 to reflect the new design.

We find this acceptable.

However, based on the October 9, 1981 SER, the applicant should provide formal documentation to the NRR staff confirming that the modification is complete (i.e., electrical schematics complete and hardware installed accord-ingly).

Therefore, this item remains confirmatory pending receipt of the re-quested formal documentation.

St.

Lucie SSER 82 7-1

7.5 Safet -Related Dis la Instrumentation 7.5.4 Post-Accident Monitoring Instrumentation The applicant states in their Letter (R. Uhrig to D. Eisenhut) dated Hay 4, 1982 that compliance to Regulatory Guide (R.G.) 1.97, Revision 2 will be com-pleted in accordance with the implementation date specified in the subject regulatory guide (June 1983) and that this date follows the St.

Lucie 2 core load date.

Also, the applicant states that plant operation is justified prior to complete implementation because most of the instrumentation required by R.G. 1.97, Rev.

2 is a part of the existing design.

In the staff's SER dated October, 1981 it was decided that the operating license should be conditioned to require compliance of the St.

Lucie 2 design with the recommendations of R.G.

1.97 Rev.

2 by June, 1983 or justification for any alter-natives should be provided.

Also, the staff committed to revi.ew any informa-tion submitted showing conformance on a schedule consistent with the implemen-tation date of June 1983.

Subsequent to the SER input described

above, the staff has proposed, as Com-mission policy, that conformance to the R.G. 1.97, Rev.

2 recomme'ndations be addressed in the broader context of the requirements for emergency response capability.

This will include the evaluation of designs and implementation schedules for the Safety Parameter Display System, Control Room Design Review, upgraded Emergency Operating Procedures, Technical Support Center, Operational Support Center, Emergency

Response

Facility, and Regulatory Guide 1.97, Revision 2.

Based on the review of the instrumentation provided for post-accident moni-toring and discussion at various meetings with the applicant, the staff con-cludes with reasonable assurance that there is substantial conformance to R. G.

1. 97, Rev.

2.

Therefore, this item will be addressed in the broader con-text of subjects as noted above and will not be included as a separate license condition.

To be consistent with the proposed Commission policy, the review of the St..Lucie 2 design for conformance to the subject regulatory guide will be performed on a schedule to be negotiated with the applicant.

St.

Lucie SSER ¹2 7-2

9 AUXILIARYSYSTEMS 9.5 Other Auxiliar S stems

9. 5. 1 Fire Protection In the SER we mentioned that we had not coordinated our fire protection site

survey, and we had not reviewed the fire protection for safe shutdown capabil-ity, including the alternate safe shutdown system.

In addition, we indicated that the licensee should provide verification that penetration seals installed in a fire rated barrier have a fire resistance rating of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

Me conducted our fire protection site survey June 1 through June 4, 1982.

Our consultant, Gage-Babcock and Associates, Inc. participated in the survey.

During our survey, we found deviations from our guidelines in the following areas:

1.

Standpipe Hose Stations - Fuel Handling Building 2.

Fire Detection Systems used to Actuate Fire Suppression Systems 3.

Control Room - Fire Detection 4.

Diesel Generator Rooms - Day Tank Curbing 5.

Battery Rooms Fire Detectors 6.

Fire Barrier Penetration Seal Verification 1.

Stand i e Hose Stations - Fuel Handlin Buildin (9.5. 1. 1.8)

In the

SER, we indicated that standpipe hose stations were provided on. 100-foot centers and are located so that any area of the plant could be reached with an effective hose stream.

During our site survey, we found that the fuel handling building did not contain standpipe hose stations.

At our request, the applicant verbally committed to provide standpipe hose sta-tions in the fuel handling building in accordance with BTP CMEB 9.5-3. Section C.6.c.

The applicant will document this commitment in a future amendment.

Based on our survey and the applicant commitment, we conclude that the stand-pipe systems are adequate and meet the guidelines of BTP CMEB ASB 9.5-1 Section C. 6. c and are, therefore, acceptable.

2.

Fire Detection S stems Used-To Actuate Fire Su ression S stems (9. 5. 1. 2. D)

In the

SER, we indicated that all fire detection systems conform to the appli-cable sections of NFPA 72D.

During our site survey, we found the methods used to transmit alarm and trouble signals from fire detection systems used to actuate fire suppression systems to the control room were not in accordance with our guidelines.

The applicant verbally committed to design and install the fire detection systems used to actuate fire suppression systems in the reactor auxiliary and diesel generator buildings so that both alarm and trouble signals will be St.

Lucie SSER 2

9-1

transmitted to the control room in accordance with NFPA 72D as recommended by our guidelines.

The applicant will document this commitment in a future amendment.

Based on our survey and the applicant's commitment, we conclude that the fire detection systems will meet the guidelines of BTP CMEB 9.5-1 Section C.5.a and are, therefore, acceptable.

3.

Control Room - Fire Detection Covera e

(9.5. 1.5.a)

In our SER, we indicated that ionization and thermal type heat detectors would be located in the control room and surrounding areas.

During our site survey, we found a lack of smoke detection capability in the southeast corner of the control room and the existing smoke detectors installed above a solid lay in tile-suspended ceiling.

The solid lay in tile-suspended ceiling will restrict the flow of products of combustion from a fire in the control room below the suspended ceiling to the area above the ceiling where the smoke detectors are installed.

This could result in a fire in the control room below the suspended ceiling propagating from its incipient stage into the flame stage before being detected by the smoke detectors.

The applicant verbally committed,to replace the solid lay in tiles with open grid lay in metal tiles and provide additional smoke detectors in the southeast corner of the control room, in order to obtain automatic fire detection coverage in this area of'he control room.

The applicant will docu-ment these commitments in a future amendment.

Based on our survey and applicant's commitments, we conclude that fire detec-tion for the control room meets the guidelines of BTP CMEB 9.5-1 Section C.7.b.

and is therefore acceptable.

4.

Diesel Generator Room - Da Tank Curbin (9.5. 1.5.d)

During our survey of the diesel generator building, we found that leakage from a fuel oil day tank could result in the spill of fuel oil throughout a diesel generator room.

The applicant verbally committed to provide water-tight curbs at the top of the east and west stairwell of both diesel generator buildings to contain 13.0X of the content of oil from a day tank.

The applicant will document this commitment in a future amendment.

Based on our survey and the applicant's commitment, we conclude the fire pro-tection for the diesel generator rooms meets the guidelines of BTP CMEB 9.5-1 Section C. 7. i. and is, therefore, acceptable.

5.

Batter Rooms - Fire Detection (9.5. 1.5.e)

During our site survey, we found that the Train A and Train 8 Safety-Related Battery Rooms did not contain automatic fire detectors.

At our request, the applicant verbally committed to provide automatic smoke detectors in the Train A and Train B safety-related battery rooms.

• The applicant will document this commitment in a future amendment.

St.

Lucie SSER 2

9-2

Based on our survey and the applicant's commitment, we conclude that the fire protection for the battery rooms meets the requirements of BTP CMEB 9.5-1 Section C. 6. g and is, therefore, acceptable.

6.

Fire Barrier Penetration Seals Verification (9.5. 1.3.a)

In our

SER, we indicated that the applicant had committed to provide 3-hour fire rated penetration seals in fire. rated barriers.

During the site survey we found the design of these penetrations had not yet been completed and veri-fied.

We will require the applicant to provide verification that the penetra-tion seals are rated for a fire resistance of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

7.

Fire Protection for Safe Shutdown Ca abilit (9.5. 1.6)

In our SER, we indicated that the applicant committed to provide fire protec-tion for safe shutdown capability in accordance with Section III.G of Appendix R to 10 CFR 50.

At the time of our site survey, we found the applicant had not completed the design.

During our site survey, the applicant described their methodology for meeting Section III.G of Appendix R.

The methodology is not consistent with our guidelines.

We also noticed deviations from Section III.G during our survey of safe shutdown systems.

During our exit meeting with the applicant on June 4, 1982, we indicated that deviations to our guidelines concerning safe shutdown capability should be docketed for review and approval by the staff.

By letter dated July 14, 1982, the applicant provided additional information concerning safe shutdown capability.

In the letter, the applicant identified deviations from our guidelines and requested approval of these deviations.

We are currently reviewing this information and will report on the resolution of this item in a subsequent safety evaluation report.

8.

Conclusion There are six confirmatory fire protection items:

1.

Providing standpipe hose stations throughout the fuel handling building in accordance with BTP CMEB 9.5-1 Section C.6.c.

2.

Design and install the reactor auxiliary and diesel generator building fire detecton systems used to actuate fire suppression systems so that all trouble and alarm signals from the systems are transmitted to the control room in accordance with NFPA 72D as recommended by BTP CMEB 9.5-l Section C.6.a.

3.

Replace all solid lay in ceiling tiles in the control room with an open metal grid lay in ceiling tile, and provide additional smoke detectors in the southeast corner of the control room to obtain automatic fire detec-tion coverage in this area of the control room as recommended by BTP CMEB

9. 5-1 Section C. 7. b.

4.

Provide water tight curbs at the doorways to each diesel generator building to contain llOX of the oil content from a day tank as recommended by BTP CMEB 9.5-1 Section C.7.1.

St.

Lucie SSER 2

9-3

5.

Provide automatic fire detection in the Train A and Train B Safety-Related Battery Rooms as recommended by BTP CMEB 9. 5-1 Section C. 6. a.

6.

Provide 3-hour fire rated penetration seals in, fire rated barriers as recom-mended by BTP CMEB 9. 5-1 Section C. 5. a.

In addition, there is one unresolved fire protection item; the fire protection of safe shutdown capability including the alternate safe shutdown system.

Our review of this item is ongoing, we will report our review of this item in a subsequent safety evaluation.

St.

Lucie SSER 2

9-4

10 STEAM AND POWER CONVERSION SYSTEM 10.4 Other Features of the Steam and Power Conversion S stem 10'.9 Auxiliary (Emergency)

Feedwater System In our SER input we stated that the Unit 2 condensate storage tank (CST2) con-tained a dedicated water volume of 300,800 gallons of which 150,400 was detailed to Unit 1 in the event of a tornado missile draining CST1 (refer to Section 9.2.6 of the SER) and 150,400 was dedicated to Unit 2.

The low water volume alarm setpoint was at the minimum dedicated water volume of 300,800 gallons.

In Amendment 6 and 7, the applicant indicated a total water volume up to the bottom of the lowest nonseismic Category I nozzle to be 307,000 gallons.

In addition, the applicant identified the dedicated water volume for Unit 1 to be 125,000 gallons and 149,600 gallons for Unit 2 with an unusable water volume of 9,400 gallons and an instrument error of 5X for an equivalent water volume of 21,400 gallons for the entire tank capacity.

This represents a total water volume of 305,400 gallons which is less than the 307,000 gallons at the lowest nonseismic Category I nozzle.

The low water volume alarm setpoint was changed in Amendment 7 from 300,800 gallons to 307,000 gallons.

We conclude that these changes are acceptable and do not affect the conclusions in the SER.

St.

Lucie SSER 2

10-1

13 CONDUCT OF OPERATIONS

13. 1 Introduction

13. 1. 1 Management and Technical Support Organization I

13.1.1.1 Home Office Organization Since the issuance of the Safety Evaluation Report, NUREG-0843, in October

1981, the applicant has issued Amendments 7, 8, 9, and 10 to the FSAR.

These amend-ments make typographical or editorial changes, account for title changes of personnel, and describe a reorganization of the home office organization.

The typographical/editorial changes and title changes have been reviewed, are satis-

factory, and will not be discussed further.

The reorganization consisted of splitting the functional area controlled by the Vice President of Power Resources at the existing nuclear and fossil subareas and placing the nuclear function under a

new vice president level position entitled "Vice President of Nuclear Energy."

The stated reason for this change is to increase the level of exclu-sive nuclear power plant management and control to the vice president level.

This arrangement is shown in Figure 13. 1.

The major organizational components of the new Nuclear Energy Department are shown in Figure 13.2, and those of the remaining Power Resources Department are shown in Figure 13.3.

We find that this reorganization serves to emphasize nuclear operations and is acceptable.

13.3 Emer enc Plannin 13.3. 1 Introduction The staff's evaluation of the applicant's emergency plan is provided in Section 13.3 of the

SER, dated October, 1981 (NUREG-0843).

The St.

Lucie Plant Radio-logical Emergency Plan (hereinafter referred to as the Plan) as amended Septem-ber 1, 1981, was reviewed against the requirements of 10 CFR 50.47(b), Appendix E to 10 CFR 50, and the criteria of 16 planning standards in Part II of NUREG-0654/FEMA-REP-l, Revision 1, November 1980, which has been endorsed as Regula-tory Guide 1. 101 (Rev. 2).

In the SER the staff specifically identified those items for which additional information, as committed by the applicant on Septem-ber 24, 1981, was to be provided.

The applicant has provided the staff with additional information in response to the unresolved items.

On January 29, 1982, Florida Power and Light Company (FP8L, applicant) submitted Revision ll to the Plan.

On July 14, 1982, the applicant submitted additional informati'on which addressed concerns raised during the FP8L/NRC telephone conference on April 8, 1982.

The applicant's responses to the unresolved items have been evaluated and are discussed in Section 13.3.2 of this supplement.

Section 13.3.3 of this supplement addresses the NRC's review of the Federal Emergency Management Agency's (FEMA) findings and determinations as to the St.

Lucie SSER 2

13-1

adequacy of State and local emergency response plans.

Section 13.3.4 addresses the State of Florida Department of Transportation (DOT) Analysis of Hutchinson Island Traffic.

Section 13.3.5 provides the staff's conclusions.

13.3.2 Evaluation of the Emergency Plan The applicant's responses to the unresolved items previously identified by the staff and committed to by the applicant have been evaluated and are discussed below.

The order of presentation cor'responds to the listing of items that appear in Section 13.3.2 of the SER.

13. 3. 2. 1 Assignment of Responsibility (Organizational Control)

Provide u dated a reement letter with De artment of Ener Savannah River 0 eration Office (DOE-SROO) and submit u dated State and local lans.

Appendix G of the Plan now contains an agreement letter, dated June 30,

1981, with DOE-SROO.

On Apri 1 16, 1982, the applicant submitted to the NRC a copy of the State of Florida emergency plan.

The staff has received information from FEMA that the current State of Florida emergency plan is being completely revised and will be forwarded to FEMA Region IV for review and evaluation in late 1982.

An updated State plan will be submitted by the applicant when avai 1 abl e.

Based on our review of their Plan and submittal as discussed

above, we find that the applicant has provided as acceptable response to these items.

13.3.2.2 Onsite Emergency Organization Clarification of Table 2-2a of the Plan Table 2-2a of the Plan has been clarified with regard to the positions discussed in Section 13.3.2.2 of the SER.

Based on our review of their Plan and submittal as discussed

above, we find that the applicant has provided an acceptable response to this item.

Provide Letters of A reement for Institute of Nuclear Power 0 erations INPO Combustion En ineerin CE and Radiolo Associates Inc..

u date the letter with the Radiolo ical Emer enc Evaluation Facilit (REEF and the REEF Medical Plan.

and rovide additional s ecification in letters with St.

Lucie Count and Martin Count Sheriffs Lawnwood Medical Center and the St.

Lucie Count Fort Pierce Fire District.

The Plan contains new agreement letters with INPO and Radiology Associates, Inc., upgraded letters with REEF, St.

Lucie County and Martin County Sheriffs and St.

Lucie County - Fort Pierce Fire District, and an upgraded REEF Medical Plan which includes a support agreement from Mount Sinai Medical Center and the DOE Radiation Emergency Assistance Center Training Site.

The upgraded letter with Lawnwood Medical Center (November 9, 1981) does not contain specific infor-mation as to the capability for 24 hour-per-day support and handling of contam-inated patients.

However, under correspondence dated July 14, 1982, the appli-cant provided an excerpt from the Lawnwood Medical Center Disaster

Manual, St.

Lucie SSER 2

13-2

revised June 20, 1981, which contains details on the support and handling of contaminated patients.

Additionally, an updated agreement letter (January 14, 1982) between FP8 L and Radiology Associates, Inc. provides for radiological emergency

care, on a 24 hr-per-day basis, at Lawnwood Medical Center.

The Applicant is currently negotiating an emergency services agreement with CE.

The applicant has provided, under correspondence dated July 14, 1982, an "expla-nation page" that will be incorported in Appendix G of the next Plan revision unless the agreement is finalized prior to that.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to this item.

Provide an onsite shift and au mentation ca abi lit that meets the s ecific staffin recommendations ex ressed in Table B-1 of NUREG-0654.

Table 2-2a of the Plan has been clarified, as discussed

above, and now meets the on-shift staffing recommendations'xpressed in Table B-1 of NUREG-0654.

Regarding the augmentation capability, in correspondence dated November 24,

1981, FP8L stated their intent to maintain the capability to provide timely augmentation of plant staff for response to radiological emergencies and com-mitted to ensuring that the plant staff can be augmented to the levels speci-fied in Table B-1 of NUREG-0654, Revision 1, within 45 to 75 minutes of notifi-cation.

On January 22, 1982, the NRC requested additional information on each of the major emergency functional duties listed in Table B-l, the extent to which the augmentation times conform to the staff's guidelines of 30 and 60 minutes.

The response was to include the applicant's consideration of addi-tional measures to assure timely staff augmentation.

On March 2, 1982, the applicant provided a response to the NRC's request for additional information.

However, the applicant's response did not provide a

portion of the requested material, viz, the extent to which the augmentation times conform to the guidelines of 30 and 60 minutes for each of the major functional duties described in Table B-1 of NUREG-0654.

R On June 22,

1982, NRC Region II issued a Confirmation of Action Letter (CAL) confirming a commitment by FP8 L to furnish the details on how the company intends to meet the objectives of Table B-1 of NUREG-0654, Rev. 1.

The applicant's reply to the CAL, dated July 22, 1982, contains a description of time.-saving measures which, when implemented, will provide shift augmenta-tion times that conform to the guidance of Table B-1 of NUREG-0654.

The appli-cant has committed to furnish the results of three call-in drills which incor-porate the time-saving measures.

We consider the July 22 reply to be an accept-able response to the CAL.

Under correspondence dated September 3, 1982, the applicant committed to revise the Plan to reflect the upgraded capability.

Based on our review of their submittals as discussed

above, we find that the applicant has provided an acceptable response to this item.

St.

Lucie SSER 2

13-3

13.3.2.3 Emergency

Response

Support and Resources Provide additional s ecification re ardin

,the accommodation of NRC and FEMA ersonnel at, the, EOF.

s ecific licensee State and local resources available to su ort Federal res onse and ex ected arrival times of Federal assistance.

Section 2.3.4 of, the Plan describes the means for accommodating NRC and FENA personnel at the interim EOF, and specifies the licensee, State and local resources available to support the Federal response and the arrival times of Federal assistance at the site.

Based on our review of their Plan and submittal as discussed

above, we find that the applicant has provided an acceptable response to this item.

13.3.2.4 Upgraded Emergency Classification System The staff's review of the Emergency Classification System contained in Rev.

11 to the Plan has been completed.

Me conclude that the applicant must make several additions and-clarifications to the classification and EAL section (Table 3-1) of the Plan.

Under correspondence dated August 24, 1982 and

'eptember 3, 1982, the applicant furnished additional information which satis-fied the staff's concerns regarding the EALs.

Further, the applicant committed to incorporate the EAL changes into Table 3-1 of the Plan by. December 31, 1982.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to this item.

13.3.2.5 Notification Methods and Procedures Provide a follow-u messa e format from the facilit to offsite authorities a

eneral descri tion of the Alert and Notification S stem and a descri tion of written messa es intended for the ublic.

Table 4-2B of the Plan conta'ins a follow-up message format from the facility to offsite authorities.

The actual message form, used by the Emergency Coordi-nator to notify offsite authorities, contains the information recommended by NUREG-0654 and may be found in Emergency Plan Implementing Procedure (EPIP)3100021E, Rev.

11.

Section 5.2.8 of the Plan provides a general descrip-tion of the Alert and Notification System that has been installed and tested at the St.

Lucie site in accordance with the requirements of Section IV.D.3 of Appendix E to 10 CFR Part 50.

Tables 6-1 to 6-7 of the Plan provide examples of written messages intended for the public.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to this item.

13.3.2.7 Public Education and Information Provide for annual dissemination of information to the ublic and rovide a reference to the State lan which describes a coordinated communications arran ement for'rumor control.

St.

Lucie SSER 2

13-4

Section 6.1.2 of the Plan provides for conduct of the public educational pro-gram on an annual basis.

Section 6.3 of the Plan specifies that the timely exchange of information among designated spokespersons will aid in dispelling most rumors.

An "Emergency Measures" brochure distributed to the public in Martin and St.

Lucie Counties contains information on the means for obtaining timely and accurate information.

The brochure will be updated and disseminated annually to the public in the plume exposure pathway emergency planning zone.

Based on our review of their Plan and submittal as discussed

above, we find that the applicant has provided an acceptable response to this item.

13.3.2.8 Emergency Facilities and Equipment Include in the Plan a listin of Area and Process Radiation Monitors and other onsite monitorin s stems that are s ecificall relied u on in the emer enc classification scheme and describe the rovisions for a coor-dinated environmental radiolo ical monitorin ro ram.

Tables 3-2 and 3-3 of the Plan provide a listing of process and area monitors, respectively, that are used in the emergency classification 'scheme.

Other on-site monitoring systems (Criterion H-5 of Section II to NUREG-0654) were not addressed in the Plan.

Under correspondence dated July 14, 1982, the applicant committed to incorporate in the next Plan revision Table 3-4 which is a listing of non-radiological instrumentation used for accident detection and emergency classification.

Section

5. 1.6 of the Plan describes the environmental moni-toring program which is coordinated with State and Federal agencies.

Based on our review of their Plan and submittal as discussed, we find that the applicant has provided an acceptable response to this item.

Emer enc Res onse Facilities ERF)

The ERFs include the Technical Support Center, Emergency Operations Facility and the Operations Support Center.

The interim ERFs proposed for St.

Lucie 2 appear to be adequate to meet the requirements of 10 CFR 50.47(b)(8) and Part 50, Appendix E as interim facilities.

The conceptual design of the final ERFs is under review by the NRC staff and an evaluation of these facilities will be provided.

The facilities will be completed on a schedule consistent with that established for operating plants.

13.3.2.9, Accident Assessment Identif the s ecific rocedures which describe the methods and techni ues to be used for determinin source terms.

Section

5. 1.4 of the Plan specifies that the containment high range radiation monitors can be used to determine concentrations of radionuclides based upon isotopic mixes assumed for accidents described in the FSAR.

Specific source terms can be determined using EPIP 3100033E, "Offsite Dose Calculations,"

Revi-sion 4, for all monitored release points and grab samples.

If the effluent monitor s are inoperable and a loss of coolant accident has occurred, an esti-mate of the potential release rates for noble gas and iodine can be made by applying the readings on the containment high range radiation monitors to St.

Lucie SSER 2

13-5

EPIP-3100033E.

As a followup to their commitment of July 13,

1982, on August 10, 1982, the applicant furnished the NRC the bases for the offsite dose calculations.

4 Based on our review of their Plan and submittal as discussed

above, we find

. that the applicant has provided an acceptable response to this item.

Discussion and Conclusions on Items (2) thru (6)

The applicant has addressed Items (2) thru (6) identified in Section

13. 3. 2. 9 of the SER; A description of the plant monitoring systems that meet NUREG-0737 requirements, meteorological data displays for Unit 2 control room, procedures on offsite monitoring capability, procedures on detection and measurement of radioiodine, and procedures that describe the means for relating measured parameters to dose rates and integrated dose have been included in the Plan.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to these items.

13.3.2. 10 Protective

Response

Provide u

raded evacuation time estimates The supplemental information transmitted by the applicant on September ll, 1981, regarding evacuation time estimates-has been reviewed pursuant to NUREG-0654, Revision 1.

The information was sufficient to render a determination that their estimates adequately addressed the noted deficiencies identified in cor-respondence from the NRC dated August 24, 1981.

Figure 5-2 of the Plan illus-trates the evacuation analysis area"and Tables 5-4 and 5-5 describe the range of clear time estimates for normal and adverse

weather, respectively.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to this item.

y Discussion and Conclusions on Item 1

to (5)

The applicant has addressed items (1) thru (5) identified in Section 13.3.2. 10 of the SER.

A description of the monitoring and decontamination capability at the offsite assembly

area, an alternate evacuation route for site personnel, provision for accountability of all onsite individuals within 30 minutes of the declaration of an emergency, a summary of evacuation time estimates, and EPA Protective Action Guides have been included in the Plan.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to these items.

13.3.2. 11 Radiological Exposure Control Discussion and Conclusions on Items (1) to 4

The applicant has addressed items (1) thru (4) identified in Section

13. 3. 2. 11 of the SER.

A descriptio'n of emergency exposure gui'delines for ambulance ser-vice and medical treatment personnel procedures that shall be followed for St.

Lucie SSER 2

13-6

permitting onsite volunteers to receive emergency radiation exposure, action levels for determining the need for personnel decontamination, control measures with regard to drinking water and food supplies, and criteria for checking potentially contaminated areas prior to allowing entry for normal use have b'een included in the Plan.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to these items.

13. 3. 2. 14 Exercises and Drills Provide for unannounced drills and communication tests with lant offsite monitorin teams that include the as ect of understandin the content of messa<ees.

Under correspondence dated July 14, 1982, the applicant committed to include in the next Plan revision, provisions for at least one unannounced Communication drill (of the offsite communications system) annually.

An emergency prepared-ness drill and exercise program is to include tests of the response of emergency personnel

and, as such, provision should be made for additional unannounced drills involving fire, medical emergency, health physics monitoring, evacuation and accountability.-

On August 27, 1982, the applicant was contacted by tele-phone to discuss such a program.

By correspondence dated September 3, 1982, the applicant committed to include in the overall drill and exercise program provisions for unannounced drills which satisfy the criteria of NUREG-0654.

Further, the applicant committed to revise the Plan to incorporate this pro-vision by December 31, 1982.

Section

7. 1. 4. 2 of the Plan describes radiological monitoring drills which in-clude communication tests involving the aspect of understanding the content of messages.

Based on our review of their Plan and submittals as discussed

above, we find that the applicant has provided an acceptable response to these items.

13. 3. 2. 16 Responsibility for the Planning Effort I

t Identif b title the individual with the overall authorit and res onsibilit for radiolo ical emer enc res onse lannin Section

7. 3 of the Plan specifies that the overall authority and responsibility for radiological emergency preparedness and planning lies with the Director, Nuclear Energy.

Based on our review of their Plan and submittal as discussed

above, we find that the applicant has provided an acceptable response to this item.

13.3.3 Review and Evaluation of State and Local Plans by FEMA Following a Plan revision in 1981 to meet the guidance of NUREG-0654, the State of Florida Radiological Emergency

Response

Plan for Nuclear Power Facilities (State REP) has been undergoing an ongoing review by FEMA RAC IV.

A full-scale emergency exercise, including participation by State and local agencies, was held at St.

Lucie on February 10-11, 1982.

St.

Lucie SSER 2

13-7

FEMA s interim findings, based on a draft plan submitted by the State of Florida and,FEMA's observation of the St.

Lucie exercise, conclude that while plan and plan execution improvements are

needed, the State of Florida and the involved counties are capable, of implementing thei,r planned response to an offsite release at St.

Lucie.

These interim findings are included in Appendix E

of this SSER.

Supplemental information regarding the plan improvements will be provided by FEMA.

The NRC staff's. overall conclusions regarding offsite preparedness will be provided following our receipt and review of the addi-tional information.

13.3.4 NRC Review of the State of Florida DOT Analysis of Hutchinson Island Traffic r

On April 20, 1982, the district office of the Florida State DOT issued a study on the projected traffic conditions on Hutchinson Island.

The St.

Lucie Nuclear

- Plant is situated approximately midway on this 20-mile long barrier reef island.

The study concludes that prior to full development of currently premitted pro-

jects, the Hutchinson Island roadway system will be over capacity.

The staff has reviewed the DOT roadway, study and concludes that"while the pro-jected growth will result in undesireable peak-hour traffic conditions, the current roadway system is adequate.for evacuation of the public on Hutchinson Island consistent with the evacuation time estimates discussed above in Section

13. 3. 2. 10.

In a letter to FEMA on May 27, 1982, the staff recommended that FEMA's review and evaluation of State and local plans for the St.

Lucie site take into account the results of the Hutchinson Island traffic study with regard to future evacua-tion plans for the Island.

f 13.3.5 Conclusions Based on its,review of the applicant's Plan and its review of the FEMA evalua-tion made to date of State and local plans, the staff concludes that the state of onsite emergency preparedness

-provides reasonable assurance that adequate protective measures can and will be taken in the event of a radiological emer-gency during operation up to 5%%uo power.

The license will be conditioned to.

require final FEMA findings and determinations of offsite preparedness prior to operations above 5X power.

After receiving further findings and determinations made by FEMA on State and local emergency response

plans, and after confirming that further revisions of the Plan address the applicant's commitments, a supplement to this report will provide the staff's overall conclusions as to whether the state of onsite and offsite emergency preparedness provides reasonable assurance that adequate protective measures can and will be taken in event of an emergency during operations above 5X power.

St.

Lucie SSER 2

13-8

13.5 Plant Procedures 13.5. 1'dmiriistrative Procedures 13.5. 1. 1 Administration Procedures, Comparison with Crite'ria This section adds TMI Task Action Plan Item I.C.5 - Procedure for Feedback of Operating Experience to Plant Staff - which was omitted from the original SER.

This item is controlled by corporate and site procedures presently in place for Unit 1.

The following safety evaluation for Unit 1 is extracted from an NRR-to-FPL letter of February 4, 1982 (Clark to Uhrig).

"FPL has developed both corporate and site procedures in response to this item.

These procedures clearly identify a Program Administrator within the Power'esources Department at the corporate headquaters.

An operational Review Group charged with review responsibility for priority items is also established with membership including repre-sentatives from several corporate departments and the nuclear plants.

The initial review of'perational experiences

'received from sources external to FPL is conducted at the corporate headquarters and coor-dinated by the Program Administrator, who also coordinates the actual feedback to the plant technical staff.

"Plant procedures provide for a designated technical staff member to determine affected departments, route feedback to these departments, collect responses

needed, and provide plant responses to the Program Administrator.

Plant departments take action to resolve items re-ceived from the technical staff, including committed completion dates for priority items.

Corrective action may include, for example, training, procedure changes or equipment modifications.

Departments retain records of personnel trained on feedback items for a minimum of six months.

Procedures changes, if needed, are made in accordance with normal plant procedures.

"The corporate review and on site routing to department heads is viewed as an effective means to limit conflicting information and wholesale distribution of extraneous, or. unimportant information.

"Based on this review, we find the FPL procedures for feedback of operat-ing experience to the St.

Lucie Unit 1 staff to be acceptable."

Since this is a

common area of endeavor, TMI Task Action Plan Item I.C.5 is acceptable for Unit 2 also.

13.6 Ph sical Securit Plan The applicant has submitted security plans entitled "St.

Lucie Security Plan, Revision 6," "St.

Lucie Plant Security Training and gualification Plan,"

and "St. Lucie Contingency Plan," for protection against radiological sabotage.

The plans were reviewed in accordance

'with Section 13.6, "Physical Security" of the July 1981 edition of the "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants."

(SRP, NUREG-0800)

St.

Lucie SSER 2

13-9

As a result of our evaluation, certain portions of the plans were identified as requiring additional information and upgrading to satisfy the requirements of Section 73.55 and Appendices B and C of 10 CFR 73.

In response to this evaluation, the applicant filed revisions to these plans which satisfied these requirements.

These revised plans are considered to be in compliance with the Commission's regulations contained in 10 CFR Parts 50, 70, and 73.

The "St.

Lucie Plant Security Training and qualification Plan" and "Contingency Plan" have been determined to meet the requirements of Appendix 8 and C of 10 CFR Part 73 and therefore are acceptable.

An ongoing review of the progress of the implemen'tation of the approved plans will be performed by the staff to assure conformance with the performance requirements of 10 CFR Part 73.

The identification of vital areas and measures used to control access to these

areas, as described in the plan, may be subject to amendments in the future.

We have determined that the above referenced plans contain. Safeguards Informa-tion which must be protected against unauthorized disclosure in accordance with 10 CFR 73.21.

St.

Lucie SSER 2

13-10

Executive, Vice President Vice President Advance and Systems 8 Technology Vice President Engr. Project Hgr.

& Construction Vice President Power Resources Vice President Fuel Res.

5 Corp.

Development Vice President Nuclear Energy Vice President System Planning Figure 13. 1 Florida Power and Light Co. major organizational components reporting to Executive Vice President 13-11

Vice President Nuclear Energy Manager of Nuclear Energy Site Manager PTP Assistant Manager Nuclear Energy Plant'Manager Fossil - PTP Plant Manager Nuclear -

PTP Plant Manager PSL Manager Nuclear Energy Services Operations Supt.

PSL - II Section Supe'rvisor Plant Support Section Supervisor Codes and Inspection NE Specialist Licensing NE Supervisor Emergency Planning NE Supervisor Health Physics Figure 13.2 Florida Power and Light Co. major organizational components of Nuclear Energy 13-12

Vice President Power Resources Manager Pwr.

Res.

Fossil Manager Pwr.

Res.

Services Director Power Supply Various Fossil Plant Managers Section Supervisor Operations Various System Functions Section Supervisor Administration Section Supervisor Instr.

8 Control Section Supervisor Test and Performance Section Supervisor Maintenance Section Supervisor Performance and Planning Figure 13.3 Florida Power and Light Co. m'ajor organizational components of Power Resources 13-13

15 ACCIDENT ANALYSIS 15.5 Reactor Coolant Pum Shaft Seizure and Shaft Break In Section 15.5 of the SER, the staff reported that the analysis provided by the applicant did not give sufficient information to allow the staff to judge compliance with the acceptance criteria.

The applicant was required to provide DNB plots, event sequences and a demonstration that the analysis considered the limiting single failure concurrent with SG tube leakage (Tech.

Spec.

value) and loss of offsite power.

In Amendment 9 to the FSAR, the applicant has provided the results of the analysis for the above stated event combination.

The rapid reduction in reactor coolant flow caused by the RCP shaft seizure results in an increase in core average coolant temperature, a corresponding reduction in the margin to DNB, and an increase in RCS pressure.

A low flow trip signal is generated within the first second of the transient.

Also, at the end of the first

second, the turbine/generator is tripped which is assumed to result in a loss of offsite power and subsequent coastdown of the remaining three RCPs.

The event results in a transient minimum DNBR of 0.362 at 3.6 seconds of the transient.

The percentage of fuel pins which are calculated to experience DNB is 13 percent.

The calculational method presented in CENPD-183 (this topical report has been approved by the staff) was used to calculate the fuel pins which experience DNB.

For the purpose of radiological release calculations, all fuel rods that experience DNB are assumed to fail.

The results of the analysis showed a two-hour thyroid dose at the exclusion boundary of less than 30.0 rem and a maximum RCS pressure of 2427 psia.

For the above event combination plus a postulated single active failure of a safety related component, the staff acceptance criteria is that the offsite doses at the exclusion boundary should be within the 10 CFR Part 100 guideline values.

In Amendment ll to the FSAR, the applicant has provided the results of the analysis for this event combination assuming a stuck open atmospheric dump valve as the limiting single failure.

The analysis also assumes a three seconds time delay on consequential loss of offsite power following turbine trip.

The results of the analysis showed a two-hour thyroid dose at the exclusion boundary of 28 rem and a maximum RCS pressure of'425 psia.

The staff has evaluated the applicant's analysis and has concluded that these results are acceptable.

Based on the above, the staff has concluded that the results of the applicant's analysis for a single RCP shaft seizure accident meet the staff's acceptance criteria and, therefore, are acceptable.

15. 10 Limitin Accidents

15. 10.6 Anticipated Transients Without Scram (ATWS)

This subject was described in NUREG-0843, "Safety Evaluation Report Related to the Operation of St.

Lucie Plant No. 2," October 1981.

The emergency operating St.

Lucie SSER 2

15-1

procedures for ATWS were part of the procedure review discussed for TMI Item I.C.8.

In response to our requirements on emergency operating procedures, the applicant submitted a revised emergency operating procedure for anticipated transients without scram events.

The ATWS procedure defines the actions to be taken by the operator during any event in which the reactor protection system fails to cause control rods to be inserted.

Our comments were provided to the applicant and the applicant'as incorporated them into the ATWS proce'dures.

Therefore, we conclude that, pending the outcome of the Commission rulemaking on ATWS, the procedures for ATWS are acceptable on an interim basis for full power operation of the St.

Lucie Plant Unit No.

2.

The Commission wi 11, by r ulemaking, determine any future modifica-tions necessary to resolve the ATWS concerns and the required schedule for implementation of such modifications.

St.

Lucie SSER 2

15-2

16 TECHNICAL SPECIFICATIONS The NRC staff has prepared a draft of the technical specifications to be issued as Appendix A to the St.

Lucie Unit 2 facility operating license.

These techni-cal specifications are based upon the NRC's Standard Technical Specifications for CE Plants (NUREG-0212, Rev.

3) with appropriate accommodations for design differences.

Me have concluded that normal plant operation within the limits of the technical specifications to be issued with operating license will not result in potential offsite exposures in excess of the 10 CFR 20 limits and that furthermore, these technical specifications will assure that the necessary engineered safety fea-tures will be available to mitigate accidents which may occur within the plant.

St.

Lucie SSER ¹2 16-1

17 QUALITY ASSURANCE'7:2

'~oi ti In Section 17.2 of the SER, reference is made to Figure 1 which showed the structure of'he organization for the operation of St.

Lucie Plant,. Unit No. 2, and for the establishment and execution of the operations phase QA program.

Since the SER was issued, there has been a reorganization.

,This

change, which does not affect any of our conclusions in the SER, is discussed in Section

13. 1. 1. 1 in this supplement.

A revised Figure 1 is shown on page 17-2.

17.3 ualit Assurance Pro ram J

In Section 17.3 of the

SER, we stated that the applicant committed to revise their",Topical Quality Assurance Report," which describes the QA program for the operation of St; Lucie Plant,'nit No. 2, to reflect organization

changes, commitments to new Regulatory Guides, and latest ANSI standards and editorial changes.

The applicant submitted Revision 5 to Florida Power 8 Light Company's topical report for staff review and approval.

Based on our evaluation of the 'changes described in Revision 5, we find the commitments have been met and the appli-cant's revised topical report continues to meet the criteria, of Appendix B to 10 CFR 50, and, therefore, is acceptable.

St.

Lucie SSER 82 17-1

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20 FINANCIAL UALIFICATIONS On March 11, 1982 the Commission approved SECY-82-21, a final rule eliminating entirely the financial qualifications review and findings for "electric utility" applicants, and providing that the financial qualifications of an electric utility applicant are not among the issues to be considered by atomic safety and licensing boards in construction permit or operating licensing proceedings.

This aspect of the rule is effective immediately upon publication in the Federal Register and applies to pending licensing proceedings and the issues or contentions raised therein.

Pursuant to final Regulations 10 CFR 50.2 (x) and 50.33 (f), 47 Fed.

Reg.

13750, (March 31, 1982), electric utility applicants will no longer be required to submit information on their financial qualifications and the staff "shall" not conduct any financial qualifications reviews of such applicants.

"Electric utility" in'eludes investor-owned utilities, public utility districts, municipalities, rural electric cooperatives, and state or federal

agencies, and associations of these entities.

St.

Lucie SSER 02 20-1

22 TMI-2 Requirements 22.2 Discussion of Re uirements I.C. 1 Guidance for the Evaluation and Development of Procedures for Transients and Accidents Position The position for this TMI item is described in NUREG-0843, "Safety Evaluation Report Related to the Operation of'St.

Lucie Plant Unit No. 2," October 1981.

Discussion The Combustion Engineering (CE) Owners'roup revised analysis and guidelines contained in CEN-152, (Combustion Engineering Emergency Procedure Guidelines, June 1981),

were reviewed.

Meetings were held with representatives of the CE Owners'roup in Bethesda, Maryl'and, on June 23, 24, and 29, 1982 to discuss our preliminary comments on the analysis and guidelines.

At a followup meeting in Bethesda on August 20,

1982, a revised CEN-152 was submitted which addressed a

majority of the NRC Staff concerns discussed at the June meetings.

This revised document is now under review.

Until the revised analysis and guidelines are

approved, CEN-117 and CEN-128 are being used as interim technical bases for the St.

Lucie Plant Unit No.

2 emergency operating procedures.

Based on our desk review of selected emergency'perating procedures and our observation of these procedures being exercised on a simulator and in a control room walk-through, as described in Item I.C.B, we have concluded that the interim guidelines have been adequately incorporated into the procedures.

Further revision to the procedures is expected to be necessary when the revised analysis and guidelines are approved.

This satisfies the requirements of Item I.C.l.

I.C.7 NSSS Vendor Review of Procedures Position The position for'his TMI Action Plan item is described in NUREG-0843, "Safety Evaluation Report Related to the Operation of St.

Lucie Plant Unit No. 2,"

October 1981.'iscussion

'e have reviewed selected emergency operating procedures as described in Item I.C.8 and have concluded that the NSSS vendor"s comments have been accept-ably incorporated into the selected emergency operating procedures.

The NRC Staff will,.review the power ascension test procedures to confirm that the NSSS vendor's comments on those procedures were appropriately incorporated into the procedures prior to the begining of low power testing.

St.

Lucie SSER 2

22-1

I.C.8 Pilot Monitoring of Selected Emergency Procedures for NTOL Applicants Position The position for this TMI Action Plan item is described in NUREG-0843, "Safety Evaluation Report Related to the Op'eration of St.

Lucie Plant Unit No. 2,"

October 1981.

Discussion A meeting was held in Bethesda,

Maryland, on August 17, 1982, with representa-tives of the applicant to discuss staff comments on selected St.

Lucie. Plant Unit No.

2 emergency operating procedures.

At the meeting, the staff comments resulting from our desk review of the emergency operating procedures were tentatively resolved.

On August 28, 1982, procedures that had been revised to address the Staff's comments were employed to respond to simulations of acci-dent and transient conditions.

A team of NRC and Battelle Pacific Northwest Laboratories (BPNL) personnel observed St.

Lucie Plant Unit No. 2.operators participate in simulations of several transients and accidents on the CE Simu-lator in Windsor, Connecticut.

The transients and accidents included loss-of-coolant accidents (LOCAs) in a range of break sizes, steam generator tube ruptures (SGTR) with a range of rupture sizes, loss of main feedwater, and inadequate core cooling.

Some transients and accidents were run more than once and.equipment fai lures such as failure of one emergency diesel generator, failure of scram breakers to open (ATWS), and 'failure of individual components of the emergency core cooling systems and auxiliary feedwater systems were simulated.

During the simulation of the events and following each event, the review team and the applicant's operations staff personnel discussed the operators'ctions and the procedures.

It was noted that the procedures for LOCA and SGTR could not adequately respond to a small break or rupture developing into a large break or rupture.

As a result of this exercise, additional changes were made to the draft emergency operating procedures to correct the noted weaknesses.

On August 30, 1982, the same team of NRC and BPNL personnel observe'd a control room team participate in a trial of the LOCA procedure in the St.

Lucie Plant Unit No.

2 control room.

The simulated event consisted of a small break LOCA developing into a large break LOCA.

The procedures were discussed with the applicant's operations personnel during and after the simulated events.

Addi-tional changes were made to the procedures to cori ect minor deficiencies observed.

The efficient manner in which the procedures were executed indicated that these emergency operating procedures were generally clear, properly sequenced and compatible with the control room equipment and arrangement.

To further assure the adequacy of all emergency operating procedures, we require that the applicant revise the remaining'mergency operating procedures to make the types of changes that were made to the specific procedures selected for

review, and train the operators on the revised procedures prior to full power operation.

The significant changes included use of the same format with respect to organization

'and page layouts, integration with other procedures to address a full spectrum of events, use of cle'ar, logically correct, and posi-

.tive directions to the operator, and 'location of operator directions only as action steps in the immediate and subsequent action sections of the procedures.

The NRC Staff will verify that these requirements are satisfied.

St.

Lucie SSER 2

22-2

Based on our desk review of selected emergency operating procedures and our observations of several of these procedures being used in the simulator and one in the plant control room walk-through, we have concluded, subject to confirma-tion that all of the St.

Lucie Plant Unit No.

2 emergency'perating procedures have been modified to address the comments described

above, they will be accept-able for operation at power levels up to 100 percent of rated power.

Future changes required by Task Action Plan Items I.C. 1, "Guidance for Evaluation and Development of Procedures for Transients and Accidents,"

and I.C.9, "Long-Term Plan for Upgrading of Procedures,"

are expected to 'require future revisions to the emergency operating procedures.

I.D.2 Plant Safety Parameter Display Console The safety parameter display system,(SPDS) is not yet required.

The schedule for its implementation will be developed in response to the Commission's action on SECY 82-111.

The proposed first refueling Florida Power and Light implementation schedule therefore is acceptable at this time.

II.B.1 Reactor Coolant System Vents In a letter dated May 4, 1982, the applicant has indicated that the reactor coolant system vents will not be completely installed before core load.

How-ever, this system~will be fully operational prior to operations above 5%%uopower.

We find this acceptable based on the following:

The Hydrogen rule 10,'CFR 50.44 states:

"...by the end.of the first scheduled outage beginning after July 1, 1982, and of sufficient duration to permit required modifications each light water nuclear power reactor shall be provided with 'High Point Vents.

I For plants that have recently received an"operation

license, we have interpre-ted this to mean that the plant should have RCS vents installed by initial plant startup.

However, low power testing without the RCS vents system should not significantly affect plant safety for design,b'asis accidents.

The appli-cant states that the vent system will be operable before 5X power is exceeded.

At these low power levels the potent'ial for'generation of n'on condensible gases is reduced significantly.

We therefore conclude that operation of St.

Lucie Unit 2 at up to 5X power with-out the RCS vent system completely installed is acceptable.

II.B.3 Postaccident Sampling I

I According to NUREG 0737, the'nstallation of a postaccident sampling'system is to be corn'pleted prior to core load.

By letter dated May 4, 1982, the appli-cant requested to extend this date to 12 months after core load (December 1983).

In our letter to'he applicant," dated July 26,

1982, we informed the 'applicant that this schedule delay was unacceptable.

The applicant continued to indicate in Amendment No.

11 that the postaccident sampling system will not be installed at initial plant startup but will be added as a backfit item.

Our position as stated in our letter of July 21, 1982 remains the

same, namely, that the appli-cant s justification is not sufficient; therefor'e, we find the schedular delay St.

Lucie SSER 2

22-3

unacceptable.

The applicant states that all sampling which can be performed with the post-accident sampling system can also be performed using the normal sampling sys-tem.

However, the applicant has not provided sufficient justification that the normal sampling system meets the postaccident sampling'ystem require-

ments, and therefore we cannot accept the scheduled delay.

Furthermore, all NTOLs to date have completed the postaccident sampling system prior to core load which indicates that a reasonable time has been provided for implementa-tion of the postaccident sampling system.

Completion of the postaccident sampling, system prior to core load should be a

license condition as well as the items listed in the Safety Evaluation Report, Supplement No. 1, dated December 1981.

These open items which should be com-pleted prior to exceeding 5X power are:

le. - Provide for a chloride analysis within 4 days after the reactor coolant sample is taken.

li and j. - Provide the capability to identify the activity for reactor coolant and containment atmosphere postaccident samples.'

- Provide a procedure for relating radionuclide gaseous and ionic species to estimate core damage.

In addition to the above licensing conditions, we will require that the appli-cant submit data supporting the applicability of each selected analytical chem-istry procedure or on-line=instrument along with documentation demonstrating compliance with the licensing conditions 4 months prior to exceeding 5X power operation, but review and approval of these procedures will not be a condition for full power operation.

In the event our generic review determines a speci-fic procedure is unacceptable, we will require the applicant to make modifica-tions as determined by our generic review.

II.E.4.2 Containment Isolation Dependability

[This evaluation addresses the issue of valve operability on the purge system isolation valves.

The Containment Systems Branch will address the remainder of this issue.]

Requirement Containment purge valves that do not satisfy the operability criteria set forth in Branch Technical Position CSB 6-4 or the Staff Interim Position of October 23, 1979 must be sealed closed as defined in SRP 6.2.4, item II.6.f, during opera-tional modes other than cold shutdown and refueling.

Furthermore, these valves must be verified to be closed at least every 31 days.

Applicants must be in compliance with this position before they receive their operating license.

St.

Lucie SSER 2

22-4

S stem Descri tion The St.

Lucie Plant Unit 2 has two purge systems:

a 48" purge system and an 8" mini-purge system.

The FSAR response to II.E.4.2 states the 48" purge sys-tem will be administratively closed during normal plant operation and only opened when the reactor is in cold shutdown or refueling modes.

The 8" mini-purge system will be used during operating modes.

The 8" mini-purge system consists of two 8" lines penetrating containment.

The mini-purge outlet line consists of a bell mouth open to the inside of containment followed by a vertical run of straight pipe with a butterfly valve (I-FCV-25-20) 3'2" downstream of the opening.

Valve I-FCV-25-20 is followed immediately by a 90'ipe elbow and a run of straight horizontal pipe through the containment annulus.

The second isolation valve, I-FCV-25-21 is a butter-fly valve approximately 124" downstream of the pipe elbow.

The mini-purge inlet line consists of a bell mouth outside containment followed by a butterfly isolation valve I-FCV,-25-26.

The outside isolation valve is followed by a run of straight horizontal pipe through the containment annulus.

The inside isolation valve is a swing check valve, I-V-25-25.

During a LOCA

event, pressure would build up in containment, the flow through the mini-purge inlet line would be in the reverse direction, and the,check valve would swing shut.

The 8" butterfly valves in the mini-purge lines are Pratt Model 1200 with a 1.125-inch shaft.

The valves are Class 150 (pressure rating) with Bettis Model N 721C-SR40 operators.

The valve discs are offset asymmetric design.

The 8" mini-purge swing check valve is manufactured by GPE, Controls to ASME III, Class 2 standards.

The check valve is designed,to open at 1.4 inches Hzo and is spring loaded to insure closure as containment pressure approaches atmo-spheric.

The check valve has a design pressure of 150 psig and is differen-tial pressure tested at 75 psig.

The valves included in this review are:

Purge Inlet I-FCV-25-26 I-V-25-25 Purge Outlet I-FCV-25-20 I-FCV-25-21 The following qualification Approach and Evaluation are for the 8" mini-purge valves listed directly above.

qualification was not submitted for the 48" valves as they are to remain closed above cold shutdown.

ualification A roach A.

8" Pratt Butterfly Valves guali'fication analysis for the St.

Lucie 2 mini-purge butterfly valves was per-formed by Pratt.

A description of the tests performed was not submitted by Florida Power 5 Light (FP5L).

However, during a meeting on August 20,

1981, St.

Lucie SSER 2

22-5

with members of the NRC staff, Brookhaven National Lab staff and Henry Pratt Valves, the Pr att model valve test program was described to consist of a 5-inch model valve representing in shape and aspect ratio the Pratt line of disc designs.

The test installation was configured to establish straight-line approach flow to the valves.

Torque data was recorded in order to establish torque coef-ficients.

Asymmetric disc designs were flow tested in both directions.

To determine the maximum dynamic torque resulting from through the valve, Pratt determines the maximum torque at the critical angle at initial sonic flow.

The dynamic torque equation for sonic flow is used with the appropriate dynamic torque coefficient,'edia difference, and size factors to determine the maximum valve of dynamic torque possible in the subject valve.

The maximum torque deter-mined for the 8-inch valves was 1253 in.-lbs.

The stress analysis submitted was performed for a torque of 1419 in.-lbs (the original purchase requirement).

The torque load is combined with a pressure load which exceeds the 44-psig accident pressure and static seismic loading of 3g's in each of the orthogonal axes (required is g

= 3, g

= 3, g

= 2).

The analysis provided a stress summary which showed alf of theystressek to be below allowables.'he analysis was performed on the valve body, internal parts, and the operator mo'unting.'he valve body analysis is performed to paragraph NB 3545 of Section III of the ASME Boiler and Pressure Vessel Code.

The remaining components were ana-lyzed'er a basic strength of material type approach.

The calculated stress valves were compared to code allowables, where possible, or 90 of the yield strength otherwise.

I FP8L presented information concerning actuator torque margin and actuator strength.

The operators are a Bettis Model N721C-SR40.

FP8 L indicated that this operator has a rating of 7900 in.-lbs (fully open and fully closed posi-tions) as compared to the maximum valve torque of 1253 in.-lbs predicted and 1419 in.-lbs used in'the original analysis.

Additional information available from Bettis indicates that the basic operator in this model series can be used to approximately 22,000 in.-lbs at full open and full closed and to approximately 12,500 at some intermediate positions.

The springs used in the subject valve operator can provide a torque of at least 3500 in.-lbs (full open) to approximately 1725 in.-lbs (full closed) with a low of approximately 1350 in.-lbs at some intermediate position.

Torque information provided in the Pratt report showed the combined torques tend to aid the operator spring in closure at disc angles from 90'full open) to 30' From 30 to 0 the maximum torque developed to oppose closure is the seating torque of 1217 in.-lbs.

The operators for the 8-inch mini-purge butter-fly valves have sufficient torque margin available to stroke the valve from 90'o 0'nd sufficient strength to withstand the torque loads developed.

For valve I-FCV-25-21 which is inside containment, FP8L addressed the effect of containment pressure rise on backpressure to the valve operator.

The opera-tor's cylinder incorpbrates a bleed port on the spring side of the piston and a solenoid valve is used to control pressurization and venting of the opening St.

Lucie SSER 2

22-6

side.

This design precludes the existence of a pressure differential from pis-ton opening to closing side as a result of the containment pressure.

Therefore, the venting rate of the piston is not affected by the back pressure to the extent that stroke time is increased (vs.

no-load stroke time) nor is the operator torque margin available,reduced by back pressure.

In the FP8 L submittal of March 23, 1982, the -applicant stated these valves are designed to close within 5 seconds.

B.

8-Inch GPE Spring Check Valve (GPE Controls)

The 8-inch spring check valve in the mini-purge inlet line was described as spring loaded to, close, designed to crack open at a differential of 1.4 inches of water.

During purge operations, makeup air from the, outside is admitted to containment under a differential of 3.0 inches of water.

At this low differen-tial, it would be expected that the disc would tend to float off its seat at considerably less than a full open position.

Any increase in containment pres-sure would immediately cause the disc to start to return towards the seat.

As the outside to inside differential decreases to 1.4 inches water or less, the disc would seat.

No high velocity seat impact loads are expected under a

DBA-LOCA for the St.

Lucie 2 swing check valve.

Evaluation 8-Inch Pratt Butterfly Valves:

As discussed, the analysis was based on a combination of dynamic torque loads, pressure loads (where applicable),

and static seismic loads.

Valves I-FCV-25-26, I-V-25-25, and I-FCV-25-20 have straight pipe upstream of the valve and would experience the straight-line approach flow as experienced in the Pr att butterfly valve tests.

The Pratt method of testing would be applicable to these valves.

Valve I-FCV-25-21 has an elbow upstream of the valve but.the elbow is separa-ted from the valve by approximately 124 inches of straight pipe.

This is about equal to 15 pipe diameters (150).

The separation distance (15D) is greater by two pipe diameters than the minimum distance established by ISA S39.4 for reestablishing straight line flow for a similar piping configura-tion.

The Pratt method of testing would, therefore, be applicable to this valve as well.

With two butterfly valves in series, the first valve if in a partially open position would produce a turbulence which could increase the torque coeffi-cient on the second valve by a small amount.

In the case of St.

Lucie 2, the valves are sufficiently separated as to eliminate this effect on the second valve.

The methods used by Pratt to determine the torque loads for the St.

Lucie 2 mini-purge butterfly valves are conservative.

Pratt determines the worst-case straight-line approach flow dynamic torque from choked flow for the critical angle.

In addition, flow direction was assumed to be toward the hub side which would result in higher torques than flow towards the opposite (disc flat side)

St.

Lucie SSER 2

22-7

direction.

This method of determining torque is independent of the specific pressure-time ramp curves 'for a LOCA event for each plant.

Operability of the v'alves is, therefore, independent of closure time.

As discussed in the previous section, the operators for the mini-purge butter-fly valves have been shown to have sufficient torque margin available to stroke the'valve from the fully open to the fully closed position and sufficient strength to wi.thstand the torque loads developed.

The mini-purge butterfly valves are 'equipped with handwheels.

The FP8 L sub-mittal of March 23, 1983 states the handwheels are only used in the event the air supply is. not available.

The submittal further'tates that if the hand-wheels are utilized for opening during normal plant operation, the valve will require the restoration of this inoperable valve to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or bring the plant to Hot Standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

These pro-visions should prevent accidentally overriding the Automatic Containment Isolation.

The qualification information submitted for the 8" mini-purge butterfly valves is sufficient to show these valves are capable of closure against the buildup of containment pressure from the full open (90 ) position in the event of a LOCA for the installations identified.

8-Inch GPE Swing Check Valve:

As discussed in the previous section, no high velocity'eat impact loads are expected for this valve for DBA-LOCA loads for St.

Lucie 2.

This valve is designed for 150 psig and tested at a differential pressure of 75 psig.

FP8 L has also submitted information describing the seismic qualification of this valve.

No operability problems as a result of LOCA pressures are expected to occur for this valve.

Evaluation Summar 1.

The 8-inch containment isolation mini-purge valves, I-FCV-25-26, I-FCV-25-20, and I-FCV-25-21, have been shown to be capable of closure against the build up of containment pressure from the full open (90 ) position.

2.

3.

Based on the information submitted for the 8-inch containment isolation

-mini-purge swing check valve, I-V-25-25, no operability problems are expected to occur for this valve as a"result of LOCA pressures.

qualification was not supplied for the 48-inch purge valves.

FP8 L has stated these valves will= be administratively closed during normal plant operation and only opened when the reactor in cold shutdown or refueling modes.

These valves must be sealed closed as defined in SRP 6.2.4, item II.6.f (NUREG-800), during operating conditions above 200~F in order to meet the requirements of II.E.4.2 (NUREG-0737).

Furthermore, these valves must be verified closed at least every 31 days.

St.

Luci e SSER 2

22-8

II.K.2.13 Thermal Mechanical Report - Effect of High Pressure Injection Vessel Integrity for Small-Break Loss-of-Coolant Accident With No Auxiliary Feedwater In Amendment 11 to the FSAR, the applicant has referenced a report "CEN-189" prep'ared and submitted by CE for the CE Owners Group.

Staff review of this item will be covered in NRC unresolved safety issue A-49 "Pressurized Thermal Shock."

II.K.2. 17 Potential for Voidi,ng in the Reactor Coolant System During Transients In Amendement ll'o the FSAR, the applicant has referenced a report "Effects of Vessel Head Voiding During Transients and Accidents in CE-NSSS's" prepared and submitted by CE for the CE Owners Group.

This report is being reviewed by the staff.

St.

Lucie 2 will be required to modify the operating procedures, if required after the staff completes its evaluation of the CE topic report.

We will report our evaluation of this topic report in a supplement to this SER.

II.K.3.30. Revised Small-Break LOCA Methods to Show Compliance with 10 CFR 50, Appendix K

In Amendment ll to the FSAR, the applicant has referenced

report, CEN-203 revision 1, which addresses the justification of CE small-break LOCA methods.

This report is being reviewed by the staff.

We will report our evaluation of this topic report in a supplement to this SER.

St.

Lucie SSER 2

22-9

APPENDIX A "

CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL REVIEW December, 10, 1981 Letter from applicant forwarding information regarding matrix power supply isolation device testing.-

December 10, 1981 Letter from applicant providing responses to requests

for, information.

December 11, 1981 Letter to applicant concerning long term operability of deep draft pumps.

December 14, 1981 December 16, 1981 December 16, 1981 December 16, 1981 Letter from applicant regarding its plans for submittal of information on population growth on Hutchinson Island.

Letter from appl icant transmi tting constr ucti on/start-up progress report for November.

Meeting with applicant to discuss status of open items and commitments and to identify action items needed to maintain schedules.

Generic Letter 81-40-qualifications of Reactor Operators-License Examinations.

December 17, 1981 Letter to applicant transmitting request for additional information.

December 22, 1981 Letter from applicant requesting exemption from certain requirements concerning storage and marking of safeguards information.

December 23, 1981 December 30, 1981 Letter from applicant advising that responses to certain FSAR questions will be provided by January 31, 1982.

Letter from applicant forwarding Revision 1 to environmental qualification guide book and report for safety-related elec-trical equipment, Volume 2 master list and Volume 3 component evaluation sheet.

December 30, 1981 Issuance of Supplement No.

1 to the Safety Evaluation Report.

January 4, 1982 Letter to app 1 icant transmi tting request for addi tional information.

St.

Lucie SSER 02 A-1

January 8,

1982 Letter from applicant transmitting emergency operating pro-cedures.

January 12, 1982 January 12, 1982 January 12, 1982 Letter'rom applicant advising that response to December 17 letter will be submitted by January 29.

Generic Letter 82-Ol-New Applications Survey.

Letter to applicant concerning dual licensing of St.

Lucie personnel.

January 13, 1982

'eeting with applicant to discuss fire protection and proposed third intake pipeline.

January 19, 1982 Letter from applicant forwarding responses to requests for information.

January 19, 1982 Letter from applicant transmitting "CESEC Digital Simulation of a Combustion Engineering Nuclear Steam Supply System" (proprietary).

January 26, 1982 Submittal of Amendment No.

8 to FSAR.

January 29, 1982 Letter from applicant forwarding public version of Revision ll to radiological emergency plan.

February 8, 1982 Generic Letter 82-02 Nuclear Power Plant Staff Working Hours.

February ll, 1982 Letter from applicant transmitting construction/start-up progress report for December.

February 18, 1982 Letter from applicant advising that it has no current plans to file applications for any licensing actions outlined in Generic Letter 82-01.

February 19, 1982 R

February 26, 1982 Meeting with applicant to hear -its plans on obtaining dual reactor operator licenses.

Letter from applicant transmitting construction/start-up progress report for January.

March 1, 1982 March 2, 1982 Meeting with applicant to discuss technical specifications.

Meeting with applicant to discuss results of staff review of appl icant' equipment qual ificati on program.

March 9, 1982 Generic Letter 82 Use of INPO SEE-IN Program.

St.

Lucie SSER'2 A-2

March 9, 1982 March 10, 1982 Meeting with applicant to hold seismic and dynamic equipment/

pump and valve operability pre-audit working session.

Letter from applicant forwarding summary of February 19 meeting.

March 16, 1982 March 17, 1982 March 17, 1982 Letter from applicant forwarding estimated completion dates for outstanding and confirmatory issues.

Letter from applicant advising that proposed technical speci-fications were provided at March 1 meeting.

Letter from applicant forwarding minutes of February 25 telephone conference regarding clarification of requirements for indications and alarms for the Class IE DC power system.

March 23, 1982 March 23, 1982 March 24, 1982 March 31, 1982 March 31, 1982 Letter from applicant forwarding minutes of March 2 meeting.

Letter from applicant forwarding response to request for additional information regarding mimi-purge system valves.

Meeting with applicant to discuss alternate shutdown system and to review and discuss fire protection program.

Submittal of Amendment No.

9 to FSAR.

Letter from applicant transmitting Revision 5 to Security Pl an.

April 2, 1982 April 9, 1982 Letter from applicant forwarding Revision 2 to "Environmental qualification Report and Guidebook."

Letter from applicant transmitting processed marine seismic reflection lines.

April 9, 1982 April 9, 1982 April 15, 1982 April 16, 1982 April 16, 1982 April 16, 1982 Letter. from applicant forwarding information on long term operability of deep draft pumps.

Letter from applicant transmitting minutes of March 9 meeting on Seismic qualification Review Team and Pump and Valve Operabi 1 ity Programs.

Generic Letter 82 Transmittal of NUREG-0909 Relative to the Ginna Tube Rupture.

Letter from applicant forwarding minutes of March 24 meeting.

Letter from applicant forwarding updated equipment list providing status of equipment availability for field inspection.

Letter to applicant advising that secondary water chemistry monitoring program is acceptable.

St.

Lucie SSER ¹2 A-3

April 16, 1982 Letter from applicant forwarding public version of State of Florida radiological emergency plan for nuclear power facil-ities.

April 16, 1982 Letter from applicant transmitting marine seismic reflection profiles.

April 16, 1982 Letter to applicant denying request for waiver of simulator exams requirement.

April 20, 1982 April 23, 1982 Generic Letter 82-09 Environmental qualification of, Safety-Related, Electrical Equipment.

Letter to applicant forwarding requirements list for refer-ence material to be used to administer operator license examination.

April 26, 1982 April 27, 1982 April 28, 1982 May 4, 1982 Letter from applicant transmitting construction/start-up progress report for March.

Meeting with applicant to discuss, its quality assurance program and to determine if any additional reviews will be required as a result of recent problems found in quality of design and construction at other plants.

Letter from applicant regarding arrangement for storing facility records.

Meeting with applicant to discuss radiological effluent technical specifications as well as process control program and off-site dose calculation manual.

May 4, 1982 Letter from applicant forwarding list of engineering and construction items not expected to be complete at core load.

May 6, 1982 Letter from applicant transmitting estimated completion dates for commitments identified in Safety Evaluation Report and Supplement 1 to Safety Evaluation Report.

May 7, 1982 May 7, 1982 May 11-14, 1982 May 13, 1982 Meeting with applicant to discuss and resolve any open items on fire protection.

Letter from applicant forwarding information on handling of light loads.

NRC audit by Seismic qualification Review Team and Pump and Valve Operability Review Team.

Letter from applicant forwarding construction/start-up progress report for April.

St.

Lucie SSER ¹2

May 17, 1982 May 20, 1982 May 24, 1982 Letter from applicant forwarding response to questions raised at May 7 meeting.

Letter from applicant transmitting revision to comments on Safety Evaluation Report.

Letter from applicant forwarding agenda and NRC comments and status of equipment audited by Seismic qualification Review Team and Pump and Valve Operability Review Team on May 11-14, 1982.

May 24, 1982 May 24, 1982 May 25, 1982 May 25, 1982 May 26, 1982 May 26, 1982 Letter from Ebasco forwarding information on equipment qualification.

Letter from applicant forwarding copy of test procedure utilized to verify Post Accident Sampling System Instrument-ation will function properly.

Meeting with applicant to discuss its response to IE Bul-letin 79-02 regarding base plate flexibility.

Meeting with applicant regarding safeguards program.

/

Submittal of Amendment 10 to FSAR.

Letter to applicant transmitting request for additional information.

June 1-4, 1982 June 7, 1982 Meeting and visit to give fire protection review team direct knowledge of arrangement of safety related equipment, fire hazards and fire protection equipment.

Letter to applicant transmitting request for additional information in support of confirmatory issues relating to CESEC.

June 8-10, 1982 Visit to site to review applicant's plan and schedule for completion of Unit 2 construction, to observe actual status of plant construction, and to assess scheduled fuel load date.

June 9,

1982 Generic Letter 82 Transmittal of NUREG-0916 Relative to Ginna Tube Rupture.

June 14, 1982 Letter from applicant forwarding application for amendment to construction permit to add Florida Municipal Power Agency as co-owner.

June 15, 1982 June 16, 1982 Meeting with applicant to discuss Technical Specifications.

Letter to applicant forwarding comments on Revision 5 of Security Plan.

St.

Lucie SSER 02 A-5

June 16, 1982 Letter from applicant transmitting "QA Manual,"

FPL-TQAR-100 Revision 5.

June 17, 1982 June 18, 1982 June 24, 1982 Generic Letter 82 Reactor Operator and Senior Reactor Operator Examinations.

Letter from applicant forwarding construction/startup-progress report for May.

Letter to applicant transmitting request for additional information on emergency action levels.

June 25, 1982 June 30, 1982 NRC management preliminary review meeting.

Letter from applicant concerning the protection area boundary and access post.

July 2, 1982 Generic Letter - Commission Approved Charter for the Committee to Review Generic Requirements.

July 9, 1982 July 12-16, 1982 July 14, 1982 July 15, 1982 Letter from applicant transmitting (1) minutes of meeting held on June 23 and (2) procedure for "Engineering Verifica-tion Pr ogram,"

Revi s ion 0.

On-site environmental qualification audit to review qualifica-tion documentation of safety-related equipment.

Letter from applicant forwarding (1) schedule for responding to open items and (2) responses to four open items.

Letter from applicant forwarding information on marine seismic investigation interpretation of processed data.

July 19-23, 1982 July 20, 1982 Meeting with applicant to review detail items to be placed in the Technical Specifications.

Letter to applicant transmitting draft technical report on control of heavy loads.

July 20, 1982 Letter to applicant recommending that Revision 5 to QA topical report not be issued until completion of review.

July 22, 1982 Letter from applicant forwarding construction/start-up program report for June.

July 23, 1982 Letter from applicant advising of plans to construct beach recreational facilities.

July 26, 1982 Letter to appl'icant concerning outstanding engineering and construction work items.

July 27, 1982 Meeting with Combustion Engineering to discuss its responses to staff questions on the CESEC model.

St.

Lucie SSER 82 A-6

July 27, 1982 Letter from applicant forwarding response to items identified in summary of meeti'ng held May 25, 1982.

July 28, 1982 July 30, 1982 Letter from Ebasco forwarding weekly status summary of Ebasco and Combustion Engineering Task Force for July 19-23, 1982.

Letter from Ebasco transmitting weekly status summary of Ebasco and Combustion Engineering Task Force for July 26-30, 1982.

July 30, 1982 Letter from applicant forwarding revised response to question 410.48.

July 30, 1982 August 2, 1982 August 5, 1982 Meeting with applicant to discuss IEB 79-02 and piping analy-ses open items.

Submittal of Amendment ll to FSAR.

Letter from applicant advising that the Engineering Verifica-tion Task Force will be submitting correspondence directly for next several months.

August 6, 1982 Letter from Ebasco transmitting weekly status summary of Ebasco and Combustion Engineering Task Force for August 2-6, 1982.

August 9, 1982 Letter from applicant forwarding Revision 6 to Security Plan.

August 9, 1982 August 13, 1982 Submittal of Amendment 12 to FSAR.

Letter from Ebasco transmitting weekly status summary of Ebasco and Combustion Engineering Task Force for August 9-13, 1982.

August 13, 1982 Letter from applicant transmitting procedure for "Engineering Verification Program,"

Revision l.

August 16, 1982 August 17, 1982 August 17, 1982 August 19, 1982 August 20, 1982 Letter from Ebasco transmitting minutes of August 12 meeting of Engineering Verification Program Task Force Managers Letter to applicant providing comments on its Engineering Verification Program.

Meeting with applicant to discuss staff comments on emergency operating procedures.

Letter from applicant advising of revised design of contain-ment isolation actuation signal.

Letter from Ebasco transmitting weekly status summary of Ebasco and Combustion Engineering Task Force for August 16-20, 1982.

St.

Lucie SSER ¹2 A-7

August 24-27, 1982 Meeting with applicant to review 'detail items to be placed in Radiological Effluent and Administrative Controls portions of Technical Specifications.

August 25, 1982 Letter to applicant advising of agreement that changes to security plan transmitted June 30 are consistent with pro-visions of 10 CFR 50.54(p).

August 30, 1982 August. 30-September 3,

1982 August 31-September 3,

1982 Letter to applicant transmitting staff responses to comments by the applicant on the Safety Evaluation Report.

Instrumentation and Control Systems on-site audit, including plant tour to observe the installation of equipment Power Systems Branch on-site audit, including plant tour to observe installation of equipment.

St.

Lucie SSER ¹2 A-8

APPENDIX B ERRATA TO SAFETY EVALUATION REPORT (SER)

AND SUPPLEMENT 1

TO THE SER (Unless otherwise stated all changes listed below apply to the SER)

Section 3.3.2 Pa e 3-4 First Para ra h

Second Sentence Change "3 psi in 3 seconds" to "3 psi in 2 seconds" Section 3.5.3 Pa e 3-10 Third Para ra h

Fourth Sentence Change "support structure for exhaust fans or shielding loads for exhaust fans or intake fans.

These structures are located in the auxiliary building and the condensate storage tank." to "support structure for missile barriers for exhaust fans.

These structures are located on the intake structure and the co'ndensate storage tank enclosure."

Section 3.9.3. 1 Pa e 3-24 Fourth ara ra h first sentence Change "The applicant states that all Class 1,

2 and 3 piping in essential systems" to "the applicant states that all Class 2 and 3 austenitic pipe bends and elbows in essential systems" Section 4. 1 Pa e 4-1 Second Para ra h

First Sentence Change "and is designed" to "and is being licensed" N

Section 4.2.3.2(f)

Pa e 4-17 Third Para ra h

First Sentence Change "Section 15'.5" to "Section 15.10.3" Section 4. 2. 3. 3 a)

Pa e 4-17 Second Para ra h

First Sentence Change "Section 15.6.5" to "Section 15. 10.3" Section 5.2.2. 1 Pa e 5-3 First Para ra h

Second Sentence Change "licensed power level of 2570 MWt" to "licensed power level of 2560 MWt" Section

6. l. 2 Pa e 6-2 Second Para ra h

First Sentence Change "ANSI 5. 12 Protective Coatings (Paints) for the Nuclear Industry, American National Standards Institute (1972),

and ANSI 51.2" to "ANSI N101.4, equality Assurance for Protective Coatings Applied to Nuclear Facilities, American National Standards. Institute (1972) and ANSI N512" St.

Lucie SSER 2

Section 6 ~ 1.3 Pa e 6-3 First Para ra h

Fourth Sentence Change

".1480 kilograms" to "1665 kilograms" Section 6.2. 1 Pa e 6-4 First Para ra h

Four th Sentence Change "Annual" to "Annulus" Section 6.2. 1.2 Pa e 6-7 Fourth Para ra h,

Third Sentence Change "one of two air recirculation" to "two of four air recirculation" Section 6.2.3 Pa e 6-12 Second Para ra h

Second Sentence Oelete "a recirculation fan" Section 6.2.5 Pa e 6-15 Second Para ra h

Third Sentence Change "provided for postaccident cleanup of the containment atmosphere" to "available for postaccident Hz purge of the containment atmosphere."

Section 6.3.'2 Pa e 6-18 Fifth Para ra h

First Sentence Change "two motor-operated isolation valves" to "two (one-motor operated and one-solenoid operated) isolation valves" Section 6.4 Pa e 6-24 Fourth Para ra h

Second Sentence Change "the accident signal (safety injection) or the high gaseous radioactivity signal" to "a containment isolation actuation signal or a'igh radiation signal" Section 6.4 Pa e 6-24 Fourth Para ra h

Third Sentence Change "2000 cfm" to "1550 cfm" Section 6.5.2 Pa e 6-26 First Para ra h

Second Sentence Add "in the vicinity" after "is present" Section 6.5.2 Pa e 6-26 Third Para ra h

First Sentence Add "the vicinity of" after "open baskets in" Section 6.5.3 Pa e 6-26 Second Para ra h

Third Sentence Change "by means of dampers, from exhaust to recirculation within the shield building in order" to "by means of dampers and outside air makeup lines."

Section -6.5.3 Pa e 6-27 Third Para ra h

Fifth Sentence Change "initiation activation" to "isolation actuation" St.

Lucie SSER 2

B-2

Section 8.2. 1 Pa e 8-2 Sixth Para ra h

Third Sentence Change "the 4. 16 kilovolt power to both St.

Lucie Units 1 and 2 is paralleled to facilitate continued operation of both units." to "the respective transformer of the unaffected unit is capable of supplying the required loads on both units."

Section 8.3. 1 Pa e 8-5 Second Para ra h

Delete second paragraph.

The design of these tie breakers are such that this requirement is not necessary.

Section 8.3. 1. 1 Pa e 8-6 First Para ra h

Third Sentence Change "regulatory" to "regulator" Section 8.3. l. 1 Pa e 8-6 Second Para ra h

Fifth Sentence Delete the word "four" Section 8.3. 1.2 Pa e 8-8 Second Para ra h

Second Sentence Add "are generally" after "redundant load groups" Section 8.4. 1 Pa e 8-12 First Para ra h

Sixth Sentence Delete the phrase "of appropiate color background" Section 8.4. 1 Pa e 8-12 First Para ra h

Ei hth Sentence Add the following eighth sentence in this paragraph:

"In addition, appropriate color marks are provided for all equipment."

Section 8.4.2 Pa e 8-13 First Para ra h

First Sentence Change "detection of an emergency condition" to "buses on detection of a safety injection signal on loss of offsite power."

Section 8.4.2 Pa e 8-13 Fifth Para ra h

First Sentence Change "to (1) disconnect 4 kilovolt loads on detection of a safety injection signal and (2) provide two isolation devices in series for those" to "to disconnect 4-kilovolt loads and selected 480-V loads on detection of a safety injection signal.

The applicant has also committed to provide dual fault current interruption devices for 480-V and below."

Section 9.4. 1 Pa e 9-19 Second Para ra h

Second Sentence Change "safety injection signal" to "containment isolation actuation signal" and add "for recirculation mode" after "flow path" Section 9.5.3 Pa e 9-35 First Para ra h

Third Sentence Change "4" to "8" St.

Lucie SSER 2

B-3

Section 10.3.4.3.f Pa e 10-9 First Sentence Change "site" to "side" Section 10.4. 1 Pa e 10-9 Third Para ra h

First Sentence Delete the phrase "reactor feedwater pump turbine", after "the main turbine and" Section 10.4.2 Pa e 10-10 First Para ra h

Second Sentence Change "fogging" to "hogging" Section ll.2 Pa e 11-2 Second Para ra h

Third Sentence Delte the phrase "radwaste building" after "and auxiliary building" Section 11.4 Pa e 11-6 First Para ra h

Fifth Sentence Add "or adjacent to" after "are located in" Section ll.4 Pa e 11-6 First Para ra h

Sixth Sentence Change "cement" to "a solidification agent (e. g.,

cement or cement plus sodium silicate or dow binder)"

Section 12-3.4 Pa e 12-5 First Para ra h

Second Sentence Change "39" to "41" Section 14 Item ¹6 on Pa e 14-4 Delete the statement made in item ¹6 in its entirety and replace with the following:

"The applicant demonstrated in response to question 640. 12 that testing for hot containment penetrations where coolers are not used is not required due to test results from St.

Lucie Unit l."

Section 15.'1 Pa e 15-2 Table 15. 1 Change "X of 2570 NWt + 18 MMt Rcp input" to "X of 2560 MWt + 18 MMt Rcp input" Section 15.5 Pa e 15-8 First Para ra h

Third Sentence Replace the entire third sentence to "If DNB occurs, cladding perforation should be assumed."

Section 15.10

~ 1 Pa e 15-15 Tenth Para ra h

Second Sentence Change "a

DNBR below l. 19" to "the occurrence of DNB" Section

15. 10.4 Pa e 15-20 First Third Fourth Fifth and Sixth Para ra hs All references to the word "CESEC" without a roman numeral following it should have the roman numeral II after it (e.g.,

CESEC to CESEC-II).

St.

Lucie SSER 2

B-4

Section 15.11 Pa es 15-35 15-36 and 15-38 Tables 15.6 15.7 and 15.9 under X/g values Change "6.3" to "6 7" Section

15. 11.7 Pa e 15-31 Second Para ra h

First Sentence Change "Table 15. 3" to Table 15. 5" Section

15. 11. 7 Pa e 15-31 Third Para ra h

First Sentence Change "Table 15. 1" to "Table 15.3" Table 15.8 Pa e 15-37 Change "6.7 E-4" to "6.7 E-5" and "4.0 E-6" to "5.0 E-6" Table 15.9 Pa e 15-38 Change "6.3 E-5" to "6.7 E-5" Section 17.2 Pa e 17-1 Second Para ra h

Second Sentence Replace "five" by "four"; add "and" after "Engineering and New Projects";

Delete "and St.

Lucie" Section 17.2 Pa e 17-1 Second Para ra h

Third Sentence Delete the sentence and replace with "the'Superintendent of St.

Lucie - gA, who reports to the Director of Nuclear Affairs, has an onsite Staff."

Section 17.2 Pa e 17-1 Second Para ra h

Third Sentence Change "implementing" to "implementation" Section 17.5 Pa e 17-4 Under Re ulator Guides Change "1.28" to "1.8" Section 22.2 II.B.3 Pa e 22-5 Under "License Conditions " Item e.

Change "24 days" to "4 days" Section

22. 2 II.F. 1(2d)

Pa e 22-22 "Discussion and Conclusion " First Para ra h

First Sentence Delete "not" Section 22.2 II.F.2 Pa e 22-24 Under "Saturation Mar in Monitor" Change "0-300 psia" to "0-3000 psia" and change "100-1800 F" to "200-2300 F"

St.

Lucie SSER 2

Section 23 Pa e 23-1 Item

2) in the first ara ra h

Change "CPPR-103" to "CPPR-144" Section 23 Pa e 23-1 Second Para ra h

First Sentence Change "St. Lucie Steam Electric Station Unit No.

2" to "St. Lucie Plant, Unit No. 2."

A endix C

Pa e C-20 Under "American Societ of Testin Materials S ecification."

Change "ASTM A522-70a" to "ASTM A572-70a" A

endix C

SSER ¹1 a

e C-2 Third Para ra h

Delete entire third paragraph.

A endix D

Pa e D-3 Del ete:

"LA18 - Louisiana State Highway 18" "LNED - Louisiana Nuclear Energy Division" "LOEP - Louisiana Department of'ublic Safety, Office of Emergency Preparedness" "LP8 L - Louisiana Power and Light Company" St.

Lucie SSER 2

B-6

APPENDIX C NRC UNRESOLVED SAFETY ISSUES C.5 DISCUSSION OF TASKS AS THEY RELATE TO St.

Lucie 2 A-49 Pressurized Thermal Shock Since the SER and SSER 1 was issued a new unresolved safety issue (A-49) has been defined.

This issue, pressurized thermal shock, is discussed below.

Severe reactor-system overcooling events in a pressurized water reactor (PWR) which could be followed by repressurization of the reactor vessel can result from a variety of causes.

These include instrumentation and control system malfunctions and postulated accidents such as small break loss-of-coolant accidents (LOCAs), main steam line breaks, or feedwater pipe breaks.

Rapid cooling of the reactor vessel internal surface causes a temperature gradient across the reactor vessel wall.

This temperature gradient results in thermal

stress, with a maximum tensile stress at the inside surface of the vessel.

The magnitude of the thermal stress depends on the temperature differences across the reactor vessel wall.

Effects of this thermal stress are compounded by the hoop stress if the vessel is repressurized.

As long as the fracture resistance of the reactor vessel material remains

high, such transients will not cause failure.

After the fracture toughness of the vessel is reduced by neutron irradiation, severe thermal transients could cause existing fairly small flaws near the inner surface to initiate (i.e.,

grow larger and deeper).

The vessels of most concern are those with high radiation exposure, which are made of material that has a relatively high sensitivity to radiation damage (such as those made with welds of high copper content).

For failure of the RPV to occur, a number of contributing factors must be present.

These factors are:

(1) a reactor vessel flaw of sufficient size to initiate and propagate; (2) a level of irradiation (fluence) and material proper-ties and composition sufficient to cause significant embrittlement (the exact" fluence is dependent upon materials present, i.e., high copper content causes embrittlement to occur more rapidly); (3) a severe over-cooling transient with repressurization; and (4) the crack resulting from the propagation of initial cracks must be of such size and location that the vessel fails.

The staff preliminary review of overcooling events and their probabilities included a study on overcooling events a Babcock and Wilcox (88W) plant; a

survey of operating experience on Westinghouse and Combustion Engineering plants; a review of available accident analysis in Final Safety Analysis Reports and in vendor topical reports; and a preliminary probabilistic analysis.

The preliminary results of these evaluations indicate that there is a probability of about 10-~ per reactor year that a B8W-designed plant will experience a

severe overcooling transient similiar to or worse than that experienced at Rancho Seco.

The Rancho Seco transient is the most severe overcooling transient experienced by any PWR in the United States.

The staff estimates that the St.

Lucie SSER ¹2 C-1

probability of such an overcooling event in CE-or W-designed reactors is lower, perhaps by an order or magnitude than for 88W-designed reactors.

This difference is based on design differences and on operating experience.

In the 1978 Rancho Seco transient, reactor pressure was maintained at a fairly high level (1500 psig to 2100 psig) throughout the cooldown.

The minimum temperature of the reactor coolant (280'F) during the transient was high enough so that material toughness of the reactor vessel was not significantly affected.

This evaluation leads the staff to believe that if this transient were to be repeated at Ranch Seco or any other BRW-designed facility within the next few years, the reactor vessel failure would still be unlikely.

Further, if an overcooling event such as that at Ranch Seco were to occur at any domestic

PWR, even for the vessel with the most limiting material properties in existence today, the staff would not expect a failure.

,Nonetheless, the possibility of vessel failure as a result of an overcooling event cannot be completely ruled out.

The staff conclusion is supported by ORNL analyses of the Rancho Seco event which indicate that the threshold irradiation level (neutron fluence) for crack initiation (that is, small cracks growing to larger ones assuming conserva-tive initial material porperties such as RT

= 40oF and copper content of 0.35K) would be in the range of 10 s neutro%

cm.

The highest neutron fluence to date in a B&M-designed facility is less than half the minimum value listed above.

It would, therefore, be several years before any B8W-designed facility reached its threshold irradiation level.

Some reactor vessels in CE and W facilities have somewhat higher fluences; however, other mitigating factors--such as lower values of initial RT provide a significant margin to failure should an overcooling event s)Nlar to that at Rancho Seco occur.

As a result of its evaluations to date, the staff has concluded that the probability of a severe overcooling transient (similar in magnitude to the Rancho Seco event) is relatively low.

For B8W-designed reactors, this probability is estimated to be about 10-~ per reactor per year, and for M-and CE-designed reactors, it is lower, perhaps by an order of magnitude.

Futhermore, the staff anticipates that this issue will be resolved before the irradiation history at St.

Lucie 2 is large enough to cause a

significant pressurized thermal shock concern.

Therefore, based on the foregoing, the staff concludes that St.

Lucie 2 can be operated before resolution of this issue, without undue risk to the public.

St.

Lucie SSER ¹2 C-2

APPENDIX D

3. 10 Seismic and D namic uglification of Seismic Cate or I Mechanical and Electrical E ui ment

3. 10. 1 Seismic and Dynamic qualification Our evaluation of the adequacy of the applicant's program for qualification of safety-related electrical and mechanical equipment for seismic and dynamic loads consists of (1) a determination of the acceptability of the procedures

used, standards followed, and the completeness of the program in general, and (2) an on-site audit of selected equipment items to develop the basis for the staff judgment on the completeness and adequacy of the implementation of the entire seismic and dynamic qualific'ation program.

The Seismic qualification Review Team (S(RT) has reviewed the equipment dynamic qualification information contained in the pertinent Final Safety Evaluation Report (FSAR) Sections

3. 9. 2 and 3. 10 and made a site visit on May 11 through May 14, 1982 to determine the extent to which the qualification of equipment as i.nstalled in St.

Lucie 2, meets the current licensing criteria as described in IEEE 344-1975, Regulatory Guides 1.92 and l. 100, and the Standard Review Plan Sections 3.9.2 and 3. 10.

Conformance with these criteria satisfies the applicable portions of General Design Criteria in 1, 2, 4, 14, 18 and 30 of Appendix A to 10 CFR Part 50, as well as Appendix B to 10 CFR Part 50 and Appendix A to 10 CFR Part 100.,

A representative sample of Seismic Category I mechanical and electrical equipment, as well as instrumentation, included in both NSSS and BOP scopes, were selected for the plant site review.

The review consisted of field observations of the actual equipment configuration and its installation, followed by the review of the corresponding test and/or analysis documents.

In instances where components have been qualified by test or analysis to other than current licensing criteria such as IEEE Standard 344-1975, Regulatory Guides 1.92 and 1. 100, and the Standard Review Plan Sections 3.9.2 and 3. 10, the applicant has undertaken a reevaluation and requalification program.

Based on the SgRT audit findings as discussed with the applicant during the exit meeting, we concluded that in order to complete our review, we would require the applicant to provide additional information and to clarify the details of the qualification for some pieces of equipment.

In response to these

concerns, the applicant provided post-audit submittal on June 17, 1982.

A number of concerns had since been resolved during several conference calls between the SgRT and the applicant.

Our remaining concerns are summarized below:

Generic 0 en Items A.

Piping analysis results should be checked to make sure the loading imposed by piping on all the valves and line-mounted instruments do not exceed the accelerati'on levels (G values) to which they are qualified.

St.

Lucie SSER 2

D-1

B.

C.

The applicant is committed to verify that input G levels specified for purchasing of valves and line-mounted instruments are larger than the actual computed G valves from piping stress analysis.

This will be completed by 8/31/82.

Provide verification and written justification that unqualified limit switches will not hamper operation of any of the safety-related valves.

The applicant is committed to provide.this verification for the staff review by 8/31/82.

Provide schedule of seismic and dynamic qualification of safety-related equipment not yet qualified.

A status report on seismic and dynamic qualification of equipment should be sent to the staff on a monthly basis.

D.

E.

F ~

The applicant is committed to provide this information by 8/31/82.

During the field inspection of a 4.16-kV switchgear, it was discovered that a transformer in the switchgear cabinet was not bolted down.

The applicant is committed to correct this and a sampling made to establish that other transformers in the plant are not loose.

The applicant will provide procedure for gC review of transformer mounting and results of inspection by 7/30/82.

As to be mentioned in Specific Open Items, (k), below, during the field inspection of the 32" MSIV, it was discovered that support bracket of the MSIV, which is in the open main steam trestle area, is already rusty.

This leads to the following generic concern.

For a plant such as St.

Lucie 2, where equipment in the open is exposed to high level of humidity and salt content in the air, the applicant should demonstrate to the staff, that corrosion and/or erosion of safety-related equipment and their supports will not jeopardize the designed safety function of this equipment during earthquake.

Also verify that safety-related equipment exposed to the outside environment are protected against tornado missiles.

As defined in Part B of Regulatory Guide 1.100, IEEE Std. 344-1975 is an ancillary standard of IEEE Std 323-1974 (endorsed with exceptions by Regulatory Guide 1.89).

In accordance with this standard, for plants whose Construction Permit SER is dated July 1, 1974 or later, the seismic and dynamic testing portion of the overall qualification should be performed in its proper sequence as indicated in section 6 of IEEE Std 323-1974.

Since the applicable standard for St.

Lucie 2 is IEEE 323-1974, identify those safety-related equipment for which testing was done in a sequential manner and provide your approach and the corresponding schedule to establish conformance to the requirements of IEEE 323-1974.

S ecific 0 en Items Provide clarifying details of open items as described below:

(a)

Recorder No.

M226S (NSSS-4).

St.

Lucie SSER 2

0-2

The RRS is needed for the location on the main control board on which the recorder is installed, in order to compare with TRS of recorder for verification of acceptability.

The applicant is committed to provide this information for the SgRT review by 7/30/82.

(b)

RPS cabinet (NSSS-6).

Operability proof for this cabinet is not documented in the qualification report.

The applicant is committed to respond by 8/1/82.

(c)

HPSI Pump and Motor (NSSS-8).

The applicant is committed to provide the following for staff review:

1)

SANDE computer code verification 2) location of driver/pump foot taper pins 3) criteria for load distribution to determine foundation bolt stresses 4) verification of rigidity of pump internals 5)

The manufacturer stated in the qualification report that the pump internal is adequately designed for the pump startup load and the startup load is more severe than the seismic load.

Both of these assertions should be justified and documented by 7-30-82.

(d)

LPSI Pump and Motor (NSSS-9).

Additional more-detailed information is needed for Sections G,

H, I, and J

of the motor qualification report.

These sections deal with the stress analyses of weld of stator core and its support, motor frame end mounting flange and mounting bolts for the motor.

The applicant is committed to provide this information for the SgRT review 'by 8/31/82.

(e) 10" Butterfly Valve, Valve FCV-3301 (NSSS-13).

No stress analysis of the pins that connect the wafer to the shaft was included in the qualification report.

The applicant is committed to provide this information by 8/31/82.

(f)

Intake Cooling Water Pump (BOP-4).

The SgRT reviewed the qualification report and has the following concerns:

1)

The acceptability of method used to calculate the relative displacement between impeller and casing is in question.

2)

The stresses and forces in the bearings and wear rings have not been shown to be acceptable.

3)

For the outlet flange and case flange, bolt stresses are greater than bolt preload.

The effect of this should be determined.

St.

Lucie SSER 2

D-3

The applicant is committed to provide information about these concerns by 7/30/82.

(h)

(k)

Pressure Transmitter PT1107 (NSSS-1)

Based on the field observation, the tubing connected to the pressure transmitters appears to be very flexible.

The adequacy of the tubing support needs to be ascertained.

The applicant is committed to address this by 7/30/82.

Signal Characterizer (NSSS-5).

The Foxboro cabinet where this signal char acterizer is located does not have ID tag.

The applicant is committed to provide confirmation of ID tag installation by 8/1/82.

2" Pneumatic Operated Angle Valve, Valve LCV-2110P (NSSS-11).

The verification of the Wang computer code 2200 A/B should be provided.

The applicant is committed to provide this for the,S(RT review by 8/31/82.

12" Motor Operated Gate Valve, Valve V3517 (NSSS-12).

The verification of the computer code FE AAS6 should be provided.

The applicant is committed to provide this for the S(RT review by 9/30/82.

32" MSIV, I-HCV-08-1B (BOP 1).

This valve was qualified by analysis only.

Based on past experience of the S(RT, analysis alone is not adequate to assure operability of MSIV this size under seismic 'and other dynamic loading.

Provide a description of what additional tests will be performed to demonstrate operability against seismic and dynamic loads.

Sequential testing per IEEE 323-1974 should be addressed also.

The applicant is required to address this in an expedient manner before the valve can be regarded as seismically and dynamically qualified.

Furthermore, field observation indicated that (1) the support bracket of the valve has already corroded, and (2) airlines and bypass lines connected to the MSIVs do not have supports.

The applicant is committed to address the concern about airlines and bypass lines by 8/31/82.

As mentioned in Generic Open Items, E, the concern of the corrosi,on of the support bracket should be addressed by the applicant together with other equipment and their supports that are exposed to high level of humidity and salt content in the air.

8" Gate Valve, Valve I-MV-08-14 (BOP 2).

This SgRT was notified before the audit that supports are still not in place for piping where this valve is mounted.

The applicant is committed to verify the installation of supports and notify the SgRT by 8/31/82.

St.

Lucie SSER 2

D-4

(m)

Thermocouple

Assembly, TE-14-3A (BOP 6).

During the field inspection it was noted that the support of the rigid conduit is probably too flexible.

The applicant is committed to provide justification of support design to the SgRT for review by 7/30/82.

(n) 4.16 kV Switchgear (BOP ll).-,

The applicant is committed to justify that the field-welded mounting is at least as strong as the tested bolted mounting.

And as an action item, an additional fourth plug weld should be implemented.

The applicant is committed to address this by 7/30/82.

(o)

Batteries and Racks (BOP 13).

The applicant stated that the batteries presently in place will be changed out to similar but larger ones.

The battery racks will be enlarged also.

The change will take place in summer, 1982.

The review of test report of batteries presently in place raised the following concerns:

1)

Test report states that battery LC21 has a molded rib design which created cracks during the battery test.

The applicant is to confirm that for St.

Lucie 2, an improved design of LC21 with floating ribs is used.

2)

Test report states that one thermally aged battery cracked during rack test.

The applicant is to confirm that'model LC21 which cracked is not used for this plant.

3)

The applicant is to compare the natural frequencies for the one and two bay units tested to support extrapolation of the qualification to five bay units.

4)

.The qualification report of the new batteries and racks are to be provided.

The applicant is committed to provide the above information to the S(RT for review by 8/31/82.

The applicant is also required to notify the staff when new batteries and racks are in place.

The open items should be satisfactorily resolved, and the equipment,not yet fully qualified should be adequately qualified; both of these should be completed with sufficient time before the expected fuel loading date.

A final evaluation of seismic and dynamic. qualification program will be performed and reported in a future supplement to the Safety Evaluation Report.

3. 10.2 Operability qualification of Pumps and Valves To assure the applicant'has provided an adequate program for qualifying safety-related pumps and valves to operate under normal and accident conditions, the Equipment qualification Branch (EgB) performs a two-step review.

The first step is a review of Section

3. 9. 3.2 -of the FSAR for the description of the applicant's pump and valve operability assurance program.

This information is compared to Section

3. 10 of the Standard Review Plan.

The information provided in the FSAR, however, is general in nature and not sufficient by itself to provide confidence in the adequacy of the licensee's overall program for pump St.

Lucie SSER 2

D-5

and valve operability qualification.

To provide this confidence, the Pump and Valve Operability Review Team (PVORT), in addition to reviewing the

FSAR, conducts an on-site audit of a.small representative sample of safety-related pumps and.valves supporting documentation.

1I The onsite audit includes a plant inspection to observe the as-built configuration and installation of the equipment, a discussion of the system in which the pump or valve is located and of the normal and accident conditions under which the component must operate, and a review of the.qualification documentation (stress reports, test reports, etc.)

The two-step review is performed to determine the extent to which the qualifica-tion of equipment, as installed, meets the current licensing criteria as described in the Standard Review Plan 3. 10.

Conformance with these criteria satisfies the applicable portions of General Design-Criteria, 1, 2, 4, 14, 18, and 30 of Appendix A to 10 CFR Part 50, as well as Appendix B to 10 CFR Part 50.

The onsite audit for St.

Lucie Unit 2 was performed May 11-14, 1982.

A repre-sentative sample consisting of 8 valves and 3 pumps was chosen for review.

The sample included both NSSS and BOP equipment.

During our review a number of concerns were raised.

Some of these concerns were satisfactorily resolved by the applicant during the audit by either supplying additional information or providing additional commitments as appropriate.

The remaining concerns are 'summarized below.

Generic Concerns The preoperational test program did not include all of the safety-related valves.

Three out of the eight valves reviewed were not included.

The applicant committed at that time to include these valves in their pre-operational test program.

The applicant should additionally perform a review of all safety-related active valves to assur e they will be tested as part of this program.

This is of particular concern for the check valves as the applicant has generically excluded check valves from the active valve list.

Check valves which are required to move to perform a safety function should also be included in the preoperational test program.

Documentation of this review and the completeness of it should be submitted to the staff prior to fuel load.

During the audit the applicant presented an overview of the Generation Equipment Management System (GEMS) which is a computer program to aid in the sch'eduling of preventive maintenance and testing for all equipment.

This program will be periodically updated to include experience gained during the operation of the plant.

Equipment is included in this program as each system 'is turned over to Florida Power and Light (FP8 L).

As some of the systems were incomplete at the time of the'audit, not all of the safety-related pumps and valves were yet included on this program.

Following completion of the safety-related systems the applicant should verify and notify the staff in writing that all safety-related pumps and valves. are included on this maintenance program.

,Documentation of this review should be submitted to the staff'rior to fuel load.

St.

Lucie SSER 2

D-6'

3.

Two of the five NSSS components reviewed failed to have hydrostatic and leakage test information available in the site central file at the time of the review.

A, central file review was not performed for the BOP equipment.

Additional central file reviews should be performed by the applicant on a representative sample of pump and valve files to verify the completeness of, these files.

The results of this review should be submitted to the staff prior to fuel load.

S ecific Concerns Jamesbury 10" Butterfly Valve, FCV3301 Shutdown Cooling Control Valve The documentation package for this valve was not complete.

Hydrostatic and leakage test certification was not available at the time of the audit.

A copy of the hydro test data was provided to the staff on June 17,

'982..

In addition, as this valve is a throttling valve which will be used in the partially'pen position during most of its life and therefore constantly subjected to hydrodynamic loads, the applicant should review the effects of these, loads, particularly those which may be cyclic or vibratory in nature and assure these loads in combination with other normal and accident loads will not adversely affect the operability of this valve.

Of particular concern is cyclic or vibratory load effects on the valve pins.

Documentation of this review and the results and analysis performed is to be submitted to the,staff prior to fuel load.

Fisher Control, 1" Diaphragm-Operated Globe Valve V2650, BAMT Recirculation Isolation Valve 3.

The documentation package for this valve was also incomplete.

Hydrostatic and leakage test data was not included.

A copy of the hydro test dat~ was provided to the staff on June 17, 1982.

4 In addition, this valve was not included in the preoperational test program at the time of the audit.

The applicant agreed to include this valve at that time.

Documentation of its inclusion should be provided.

Fisher Controls, 1" Diaphragm-Operated Globe Valve HCV3648, Injection Header Isolation Valve This valve requires confirmation that the filters for the air supply to this valve are included in the GEMS program.

TRW Mission, 24" Check Valve, 21-V-7172, Containment Spray Check Valve The licensee has agreed to manually cycle this valve and the other valve of this type prior to operation to verify their ability to swing open and close.

Confirmation of this action should be provided by the licensee prior to fuel load.

St.

Lucie SSER 2

D-7

5.

Rockwell, 32" x 32" x 34" Globe Valve, I-HCV-08-1B, Main Steam Isolation Val ve This is an air-operated, Y-type, bi-directional balanced stop valve.

This valve serves two safety functions:

(j.) to close on a containment isolation signal in the event of a loss of coolant accident and (2) to close on a main steam isolation signal in the event of a main steam line break.

No prototype, model, or actual valve testing was provided for this valve for operation under full flow conditions.

The applicant was requested to provide documentation which shows by model, prototype, or similarity tests this valve will close against full flow load.

The applicant. should

, provide documentation demonstrating the valve's ability to close under full flow conditions prior to fuel load.

6.

Byron Jackson, Intake Cooling Mater Pump, ICM Pump 2A Seismic qualification Review Team (S(RT) has questioned the methodology used to determine deflections of this pump in a seismic event.

Operability of this pump will remain an open item pending results of the SgRT question.

The qualification program for the safety-related pumps and valves was not complete for a number of components at the time of the audit.

In addition to responding to the concerns addressed

above, the applicant should provide a

schedule for completion of this program.

Me will complete our review when the applicant has provided the required information as stated above and has documented the completion of their Pump and Valve Operability program.

Oocumentation required to close each of the open items addressed in this report is discussed above.

Satisfactory resolution of all the open items discussed should be accomplished prior to fuel load.

A final evaluation of the Pump and Valve Operability program will be accomplished following satisfactory resolution of the open items discussed above as well as notification that the pump and valve operability assurance program has been completed for all safety-related pumps and valves.

We will report on the results of our final evaluation of the applicant's program in a future supplement to the Safety Evaluation Report.

St.

Lucie SSER 2

D-8