Text

NUREG-0843, Supplement 2, Safety Evaluation Report Related to the Operation of St. Lucie Plant, Unit 2.
	ML19115A335
Person / Time
Site:	Saint Lucie
Issue date:	09/30/1982
From:	; Office of Nuclear Reactor Regulation
To:	;
References
	NUREG-0843 S2
	Download: ML19115A335 (112)
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NUREG-0843 Supplement No. 2

~

Safety Evaluation 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

NOTICE Availability of Reference Materials Cited in NRC Publications Most documents cited in NRC publications will be available from one of the following sources:

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The following documents in the NU REG series are available for purchase from the NRC/GPO Sales Program: formal NRC staff and contractor report~, NRC-sponsored conference proceedings, and NRC booklets and brochures. Also available are Regulatory Guides, NRC regulations in the Code of Federal Regulations, and Nuclear Regulatory Commission Issuances.

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NUREG-0843 Supplement No. 2 Safety Evaluation 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

TABLE OF CONTENTS Page 1 INTRODUCTION AND GENERAL DISCUSSION 1-1 1.1 Introduction . . . . . . . . 1-1 1.7 Summary of Outstanding Issues 1-1 1.8 Confirmatory Issues 1-2 1.9 License Conditions 1-3 1.10 Generic Issues 1-4 2 SITE CHARACTERISTICS. 2-1 2.1 Geography and Demography 2-1 2.1.3 Population Distribution 2-1 2.3 Meteorology . . 2-1 2.3.1 Regional Climatology .. 2-1 2.5 Geology and Seismology 2-1 2.5.3 Surface Faulting. 2-1 2.6 References 2-2 3 DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3-1 3.4 Water Level (Flood) Design 3-1 3.4.1 General Discussion 3-1 3.5 Missile Protection .... 3-1 3.5.3 Barrier Design Procedures 3-1 3.9 Mechanical Systems and Components. 3-2 3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment . . . . . . . . . . . . . . . . . 3-2 3.9.6 Inservice Testing of Pumps and Valves . . . . . 3-2 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment . . . . . . . . . 3-2 3.10.1 Seismic and Dynamic Qualification . . . . . . 3-2 3.10.2 Operability Qualification of Pumps and Valves 3-3 St. Lucie SSER 2 iii

TABLE OF CONTENTS (Continued)

Page 4 REACTOR ....... . 4-1 4.2 Fuel System Design 4-1 4.2.1 Design Basis . . 4-1 4.2.3 Design Evaluation 4-1 4.4 Thermal-Hydraulic Design 4-2 4.4.5 Analog Core Protection Calculator 4-2 6 ENGINEERED SAFETY FEATURES . . . . 6-1 6.3 Emergency Core Cooling System. 6-1 6.3.2 Evaluation . . . 6-1 7 INSTRUMENTATION AND CONTROLS 7-1 7.3 Engineered Safety Features Actuation System 7-1 7.3.3 Auxiliary Feedwater System . . . 7-1 7.3.6 Containment Isolation . . . . . 7-1 7.5 Safety-Related Display Instrumentation 7-2 7.5.4 Postaccident Monitoring Instrumentation 7-2 9 AUXILIARY SYSTEMS ..... 9-1 9.5 Other Auxiliary Systems. 9-1 9.5.1 Fire Protection 9-1 10 STEAM AND POWER CONVERSION SYSTEM 10-1 10.4 Other Features of the Steam and Power Conversion System 10-1 10.4.9 Auxiliary (Emergency) Feedwater System. 10-1 13 CONDUCT OF OPERATIONS 13-1 13.1 Introduction . . 13-1 13.1.1 Management and Technical Support Organization 13-1 13.3 Emergency Planning . *. . . . . . 13-1 13.3.1 Introduction . . . . . . . . . . 13-1 13.3.2 Evaluation of the Emergency Plan 13-2 St. Lucie SSER 2 iv

TABLE OF CONTENTS (Continued) 13.3.3 Review and Evaluation of State and Local Plans by FEMA . . . . . . . . . . . . . . . . . . . . . . . . 13-7 13.3.4 NRC Review of the State of Florida DOT Analysis of Hutchinson Island Traffic. . . . . 13-8 13.3.5 Conclusions . . . . . . . . . . . . . 13-8 13.5 Plant Procedures . . . . . . . . 13-9 13.5.1 Administrative Procedures. 13-9 13.6 Physical Security Plan 13-9 15 ACCIDENT ANALYSIS . . . . . 15-1 15.5 Reactor Coolant Pump Shaft Seizure and Shaft Break 15-1 15.10 Limiting Accidents . . . . . . . . . . . . . . 15-1 15.10.6 Anticipated Transients Without Scram. 15-1 16 TECHNICAL SPECIFICATIONS. 16-1 17 QUALITY ASSURANCE . . . . 17-1 17.2 Organization . . . . . . 17-1

.17.3 Quality Assurance Program 17-1 20 FINANCIAL QUALIFICATIONS 20-1 22 TMI-2 REQUIREMENTS . . . 22-1 22.2 Discussion of Requirements 22-1 St. Lucie SSER 2 v

TABLE OF CONTENTS (Continued)

APPENDICES Page A CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL REVIEW. . . . . . . . . A-1 B ERRATA TO SAFETY EVALUATION REPORT (SER) AND SUPPLEMENT 1 TO THE SER . . . . . . . . . . . . . . . . . . . . . . . . . - . . . . . . . B-1 C NRC UNRESOLVED SAFETY ISSUES. . . . . . . . . . . . . . . . . . . C-1

- D SEISMIC AND DYNAMIC QUALIFICATION OF SEISMIC CATEGORY I MECHANICAL AND ELECTRICAL EQUIPMENT AUDIT REPORT. . . . . . . . . . D-1 E REVIEW AND EVALUATION OF STATE AND LOCAL PLANS BY FEMA.. . . . . . . E-1 F PRINCIPAL CONTRIBUTORS. . . . . . . . . . . . . . . . . . . . . . . F-1 St. Lucie SSER 2 vi

TABLE OF CONTENTS (Continued)

LIST OF FIGURES 13.1 Florida Power and Light Co. major organizational components reporting to Executive Vice President . . . . . . . . . . . . 13-11 13.2 Florida Power and Light Co. major organizational components of Nuclear Energy . . . . . . . . . . . . . . . . . . . . . . . . . 13-12 13.3 Florida Power and Light Co. major organizational components of Power Resources. . . . . . . . . .. . 13-13 17.1 FP&L Organization - Operations QA . . . . . . . . . . . . . . . 17-2 St. Lucie SSER 2 vii

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 Bis the errata to the Safety Evaluation Report (SER) and Supplement 1 to the SER. Appendix C is NRC unresolved safety issues.

Appendix Dis the seismic and dynamic qualification of seismic Category I mechanical and electrical equipment audit report. Appendix Eis the review and evaluation report of state and local plans by FEMA. Appendix Fis the list of principal contributors to the staff review.

1.7 Summary of Outstanding 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) ATWS Procedures (15.10.6)

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

At this time, there remain 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 #2 1-1

1.8 Confirmatory Issues At the time of the SER issuance there were several issues which were essentially resolved to the staff 1 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)

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

For a number of confirmatory issues, the remaining action 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 Walls) (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.l(a, b, and c)) .

(5) CEA axial growth and fretting (4.2.3.l(d and g)) ..

(6) Rod pressure (4.2.3.l(h))

(7) Fuel rod mechanical fracturing (4.2.3.2(g))

(8) Seismic and LOCA loads (4.2.3.3(d))

St. Lucie SSER #2 1-2

(9) Loose parts monitoring (4.4.4)

(10) Preservice inspection results of reactor vessel (5.2.4)

(11) 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)

(12) Boron mixing test results (5.4.3)

(13)

Natural circulation cool down tests (5.4.3)

(14) Upper head voiding (5.4.3)

(15) Sump vortex test (6.3.3)

(16) Provide analysis confirming that start-up channel flux alarm setpoints demonstrate sufficient operator warning time (15.6.3)

(17) Feedwater system pipe breaks (15.10.2)

(18) Inadvertent opening of PORV (15.10.5)

(19) Steam generator tube failure (with and without AC) (15.10.4)

(20) 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) Barrier design procedures (3.5.3)

(2) 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 penetrations (8.4.3)

(9) Second fuel pool heat exchanger (9.1.3)

(10) Sound powered telephone system (9.5.2.1.0)

(11) 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) Water 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 #2 1-3

1.10 teneric 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 1 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 #2 1-4

2 SITE CHARACTERISTICS*

2.1 Geography and Demography 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 Meteorology 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 #7 and #10 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 #L-81-381, Uhrig to Eisenhut) to amend the FSAR on this subject.

2.5 Geology and Seismology 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 reflection 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 #2 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. 11 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

1. 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, Letter from R. E. Uhrig to D. Eisenhut -

responses to requests for additional information; August 4, 1981.

4. 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.

St. Lucie SSER #2 2-2

3 DESIGN CRITERIA-STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3.4 Water Level (Flood) Design 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 r~sist ~issile 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 land 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 16. 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 SA and SB. 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 #2 3-1

3.9 Mechanical Systems and Components 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. We further 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. We 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 Standard 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 11 0perability Qualification of Pumps and Valves 11 ) is reviewed under NUREG-0800 (SRP Section 3.10). Further-more, discussion of this subject is now under Section 3.10.2, 11 0perability Qualification of Pumps and Valves, 11 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 FP&L 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 Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment 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 6f ~elected equipment items to develop the basis for the staff judgement on the completeness and adequacy of the implementation of the entire seismic and dynamic qualification program.

St. Lucie SSER #2 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 11 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 1.100, 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 #2 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 #2 3-4

4 REACTOR 4.2 Fuel System Design 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 L~ss-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 (S&L) 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 S&L 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 S&L 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 S&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 S&L analysis should be recategorized as a confirmatory issue.

St. Lucie SSER #2 4-1

4.4 Thermal-Hydraulic Design 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 #2 4-2

6 ENGINEERED SAFETY FEATURES 6.3 Emergency Core Cooling System 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-Willamette 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 mitigation of ECCS performance degradation. In accordance with the requirements of NUREG-0737 (Item I.C.l),

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 1 s proposal for later installation of the low flow alarms is acceptable.

St. Lucie SSER #2 6-1

7 INSTRUMENTATION AND CONTROLS 7.3 Engineered Safety Features Actuation System 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. The 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% power. Also, additional information has been provided in the May 4, 1982 letter justifying the opera-tion of the reactor up to 5% 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 (<5%) 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%

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 5%

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 5% 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 #2 7-1

7.5 Safety-Related Display Instrumentation 7.5.4 Post-Accident Monitoring Instrumentation The applicant states in their Letter (R. Uhrig to D. Eisenhut) dated May 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 recomrnendations 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, ~ev. 2 recommendations 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 #2 7-2

9 AUXILIARY SYSTEMS 9.5 Other Auxiliary Systems 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 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months .

We 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. Standpipe Hose Stations - Fuel Handling Building (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 9.5-1 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 Systems Used To Actuate Fire Suppression Systems (9.5. 1.2.D)

In the SER, we indicated that all fire detection systems conform to the appli-cable sections of NFPA 720. 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 Coverage (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 the 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 - Day Tank Curbing (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 110% 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. Battery Rooms - Fire Detection (9.5.1.5.e)

During our site survey, we found that the Train A and Train B 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 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months . *

7. Fire Protection for Safe Shutdown Capability (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 9.5-1 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 110% 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 System 10.4.9 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 CSTl (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 5% 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 galrons 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 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. 11 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 Emergency Planning 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 (FP&L, applicant) submitted Revision 11 to the Plan. On July 14, 1982, the applicant submitted additional information which addressed concerns raised during the FP&L/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 corresponds 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 updated agreement letter with Department of Energy Savannah River Operation Office (DOE-SROO) and submit updated State and local plans.

Appendix G of the Plan now contains an agreement letter, dated June 30, 1981, with DOE-SROO. On April 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 available.

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 Agreement for Institute of Nuclear Power Operations (INPO), Combustion Engineering (CE) and Radiology Associates, Inc.;

update the letter with the Radiological Emergency Evaluation Facility (REEF) and the REEF Medical Plan; and provide additional specification in letters with St. Lucie County and Martin County Sheriffs, Lawnwood Medical Center and the St. Lucie County - 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 FP&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 augmentation capability that meets the specific staffing recommendations expressed 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 expressed in Table B-1 of NUREG-0654.

Regarding the augmentation capability, in correspondence dated November 24, 1981, FP&L 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-1, 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 1 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 8-1 of NUREG-0654.

On June 22, 1982, NRC Region II issued a Confirmation of Action Letter (CAL) confirming a commitment by FP&L to furnish the details on how the company intends to meet the objectives of Table B-1 of NUREG-0654, Rev.I.

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 specification regarding the accommodation of NRC and FEMA personnel at the EOF; specific licensee, State and local resources available to support Federal response; and expected arrival times of Federal assistance.

Section 2.3.4 of the Plan describes the means for accommodating NRC and FEMA 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. We 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 September 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-up message format from the facility to offsite authorities, a general description of the Alert and Notification System, and a description of written messages intended for the public.

Table 4-2B of the Plan contains 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 f.ound in Emergency Pl an 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 public and provide a reference to the State plan which describes a coordinated communications arrangement 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 listing of Area and Process Radiation Monitors and other onsite monitoring systems that are specifically relied upon in the emergency classification scheme, and describe the provisions for a coor-dinated environmental radiological monitoring program.

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 dat~d 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 respons~ to this item.

Emergency Response 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 Identify the specific procedures which describe the methods and techniques to be used for determining 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, 11 0ffsite Dose Calculations," Revi-sion 4, for all monitored release points and grab samples. If the effluent monitors 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.

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 upgraded evacuation time estimates The supplemental information transmitted by the applicant on September 11, 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.

Discussion and Conclusions on Ite~ (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 alt~rnate 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.

I Based on our review of their Pl~n and submittals as discussed above, we find that the applicant has provided an acceptable response to these items.

I 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 description of emergency exposure guidelines 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 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.

13.3.2.14 Exercises and Drills Provide for unannounced drills and communication tests with plant offsite monitoring teams that include the aspect of understanding the content of messages.

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 Identify, by title, the individual with the overall authority and responsibility for radiological emergency response planning.

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 their 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 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 con~ludes 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.

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% power. The license will be conditioned to require final FEMA findings and determinations of offsite preparedness prior to operations above 5% 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 5% power.

St. Lucie SSER 2 13-8

13.5 Plant Procedures 13.5.1 Administrative Procedures 13.5.1.1

Administration Procedures, Comparison with Criteria 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).

11 FPL has developed both corporate and site procedures in response to this item. These procedures clearly identify a Program Administrator within the Power Resources 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 operational 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.

11 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.

11 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. 11 Since this is a common area of endeavor, TMI Task Action Plan Item I.C.5 is acceptable for Unit 2 also.

13.6 Physical Security Plan The applicant has submitted security plans entitled 11 st. Lucie Security Plan, Revision 6, 11 11 st. Lucie Plant Security Training and Qualification Plan, 11 and 11 st. Lucie Contingency Plan, 11 for protection against radiological sabotage.

The plans were reviewed in accordance with Section 13.6, 11 Physical Security 11 of the July 1981 edition of the 11 Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants~ 11 (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 Band 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 11 st. Lucie Plant Security Training and Qualification Plan 11 and 11 Contingency Plan 11 have been determined to meet the requirements of Appendix Band C of 10 CFR Part 73 and therefore are acceptable.

An ongoing review of the progress of the implementation 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 Vice President Advance and Systems Engr. Project Mgr.

&Technology &Construction Vice President ' Vice President Power Resources Fuel Res. &Corp.

Development Vice President Vice President Nuclear Energy 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 I

I l Assistant Manager Plant Manager Plant Manager Nuclear Energy Fossil - PTP Nuclear - PTP

- Plant Manager PSL --- Manager *Nuclear Energy Services I

- Operations Supt.

PSL - II

...__ Section Supervisor 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 I

I I l Manager Manager Director Pwr. Res. Fossil Pwr. Res. Services Power Supply I I I

Various Fossil Plant Managers - Section Supervisor Operations Various System Functions

- Section Supervisor Administration

- Section Supervisor Instr. & Control

- Section Supervisor Test and Performance

- Section Supervisor Maintenance

- Section Supervisor Performance and Planning Figure 13.3 Florida Power and Light Co. major organizational components of Power Resources 13-13

15 ACCIDENT ANALYSIS 15.5 Reactor Coolant Pump 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 11 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 2425 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 Limiting Accidents 15.10.6 Anticipated Transients Without Scram (ATWS)

This subject was described in NUREG-0843, 11 Safety Evaluation Report Related to the Operation of St. Lucie Plant No. 2, 11 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 has incorporated them into the ATWS procedures. 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 will, by rulemaking, 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.

We 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 #2 16-1

17 QUALITY ASSURANCE 17.2 Organization In Section 17.2 of the SER, reference is made to Figure 1 which showed the structure of the 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 Quality Assurance Program In Section 17.3 of the SER, we stated that the applicant committed to.revise

'their "Topical Quality Assurance Report, 11 which describes the QA program for the operation of St. Lucie Plant, Unit 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 & 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 #2 17-1

Chairman of the Board Chief E..cuttv. Officer Prasldent Vlca Prntdent Corpont*

Sec:'9tary Company Nucs-r Revtew Board Chai....;;;;----- - -

Qu.lhy Auuranca Commtttff Chairman:

Vice PTH!dent Envr** Prc,t. MJt.

&c...._ .~:m~::!, I I I p=:,-:::::.*.:!. Admlni.tratot of Co,poret* Records Olrectot of Corpont* Contracta VP Adv. Sys. & Tech. becuttwVP MemMra: MamHrll*

Chief Eng. Power Plants Senior Vft VP Poww RNOUrua Dlrec:tor of VPP-RNOUrt;N 01.-.ctorof Manag* rw,. Rn. Nuc. Coo,dlnator EtMronmental VP Adv. Sya. & Tech. Nuca- Suparvisor of Dir. of Nuo. Affalra R&D Affalra Dir. of Nuc. Affalra Eaecutfvll It VP l'(lltam Plannln9 Documentary FUN EPP' Eng. Mgr.

EPP' Ene. Supv. VP Engr. Prof. Mgt. Manag*ot

&Const. Nuc...r

Participants:

Dir. of Procurement Plant Mgr. fn~otlngl and Mat. Mgt.

Manav- of VP Fuel Rn. & Corp. Dn Managwof Conaultllntll lftOIH'Otingl lnv.R~

bN. SN. CNRB Cnon--dngl Ucen.ing M9r. of Quality A..u,anca Manager of Director of Po.et RnouRN P-arSuppty Superintendan, St. Lucie

-QA M*nater of Manav- Mana1* of Chlaf Engr. PowarRNOUR.. S'(lltem Protecdon P-Plant Gan. Engr.

STAFF- M anav* of Nuclear Energy

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Ant. Project General Manag*

Asst. Manav*

Turkey Potnt AML Manag81' Site Manag* Mo-Nuc*r PTP Pwr. Rn.

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Plant Manaver- Sect. lupv.

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Plant Manager PTP FIGURE 17.1 FP & L Organization - Operations QA

20 FINANCIAL QUALIFICATIONS 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" includes investor-owned utilities, public utility districts, municipalities, rural electric cooperatives, and state or federal agencies, and associations of these entities.

St. Lucie SSER #2 20-1

22 TMI-2 Requirements 22.2 Discussion of Requirements I.C.1 Guidance for the Evaluation and Development of Procedures for Transienti 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, 11 October 1981.

Discussion The Combustion Engineering (CE) Owners' Group 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' Group in Bethesda, Maryland, 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* operating 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.8, 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.1.

I.C.7 NSSS Vendor Review of Procedures

position The position for this TMI Action Plan item is described in NUREG-0843, "Safety Evaluation Report Related to the Operation of St. Lucie Plant Unit No. 2, 11 October 1981.

Discussion We 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, 11 Safety Evaluation Report Related to the Operation of St. Lucie Plant Unit No. 2, 11 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 failures 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' actions 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 observed 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 correct 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 emergency 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, uie of cle~r, 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 operating 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.l, "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% power.

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 11 of sufficient duration to permit required modifications each light water nuclear power reactor shall be provided with High Point Vents . . . 11 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 basis accidents. The appli-cant states that the vent system will be operable before 5% power is exceeded.

At these low power levels the potential for generation of non condensible gases is reduced significantly.

We therefore conclude that operation of St. Lucie Unit 2 at up to 5% power with-out the RCS vent system completely installed is acceptable.

II.B.3 Postaccident Sampling According to NUREG 0737, the installation of a postaccident sampling system is to be completed 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 the 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; therefore, 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 system 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 5% 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.

6 - 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 5% 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 Isola~ion 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

=

System Description===

The St. Lucie Plant Unit 2 has two purge systems: a 48 11 purge system and an 8 11 mini-purge system. The FSAR response to I I.E. 4. 2 states the 48 11 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 11 mini-purge system will be used during operating modes.

The 8 11 mini-purge system consists of two 811 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 1 211 downstream of the opening. Valve I-FCV-25-20 is followed immediately by a 90° pipe 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 11 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 11 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 11 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 H20 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 Purge Outlet I-FCV-25-26 I-FCV-25-20 I-V-25-25 I-FCV-25-21 The fo 11 owing Qua l ifi cation Approach and Evaluation are for the 8 11 mini-purge valves listed directly above. Qualification was not submitted for the 48 11 valves as they are to remain closed above cold shutdown.

Qualification Approach A. 8 11 Pratt Butterfly Valves Qualification analysis for the St. Lucie 2 m1n1-purge butterfly valves was per-formed by Pratt. A description of the tests performed was not submitted by Florida Power & Light (FP&L). 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 Pratt 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, media 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 1s in each of the orthogonal axes (required is g = 3, g = 3, g = 2). The analysis provided a stress summary which showed alf of theYstresseS to be below allowables. The analysis was performed on the valve body, internal parts, and the operator mounting.

The 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 per 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.

FP&L presented information concerning actuator torque margin and actuator strength. The operators are a Bettis Model N721C-SR40. FP&L indicated that this operator has a rating of 7900 in.-lbs (fully open and fully closed posi-tions) as compared to th~ 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° to 0° and sufficient strength to withstand the torque loads developed.

For valve I-FCV-25-21 which is inside containment, FP&L addressed the effect of containment pressure rise on backpressure to the valve operator. The opera-tor1s cylinder incorporates a bleed port on the spring side of the piston and a solenoid valve i~ 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 FP&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 ~akeup 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 Pratt 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 (l5D). The separation distance (l5D) 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 valves 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 withstand the torque loads developed.

The mini-purge butterfly valves are equipped with handwheels. The FP&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 states 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or bring the plant to Hot Standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . These pro-visions should prevent accidentally overriding the Automatic Containment Isolation.

The qualification information submitted for the 811 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 seat 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.

FP&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 Summary

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. 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.

3. Qualification was not supplied for the 48-inch purge valves. FP&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 11.6.f (NUREG-800), during operating conditions above 200°F in order to meet the requirements of 11.E.4.2 (NUREG-0737). Furthermore, these valves must be verified closed at least every 31 days.

St. Lucie 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 11 CEN-189 11 prepared and submitted by CE for the CE Owners Group. Staff review of this iteni will be covered in NRC unresolved safety issue A-49 11 Pressurized Thermal Shock. 11 II.K.2.17 Potential for Voiding in the Reactor Coolant System During Transients In Amendement 11 to the FSAR, the applicant has referenced a report Effects of Vessel Head Voiding During Transients and Accidents in CE-NSSS 1 s 11 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 11 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 Letter from applicant regarding its plans for submittal of information on population growth on Hutchinson Island.

December 16, 1981 Letter from applicant transmitting construction/start-up progress report for November.

December 16, 1981 Meeting with applicant to discuss status of open items and commitments and to identify action items needed to maintain schedules.

December 16, 1981 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 Letter from applicant advisinef that responses to certain FSAR questions will be provided by January 31, 1982.

December 30, 1981 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* Suppleme~t No. 1 to the Safety Evaluation Report.

January 4, 1982 Letter to applicant transmitting request for additional information.

St. Lucie SSER #2 A-1

January 8, 1982 Letter from applicant transmitting emergency operating pro-cedures.

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

January 12, 1982 Generic Letter 82-01-New Applications Survey.

January 12, 1982 Letter to applicant concerning dual licensing of St. Lucie personnel.

January 13, 1982 Meeting 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 11 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 11 to radiological emergency plan.

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

February 11, 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 Meeting with applicant to hear its plans on obtaining dual reactor operator licenses.

February 26, 1982 Letter from applicant transmitting construction/start-up progress report for January.

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

March 2, 1982 Meeting with applicant to discuss results of staff review of applicant's equipment qualification program.

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

St. Lucie SSER #2 A-2

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

pump and valve operability pre-audit working session.

March 10, 1982 Letter from applicant forwarding summary of February 19 meeting.

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

March 17, 1982 Letter from applicant advising that proposed technical speci-fications were provided at March 1 meeting.

March 17, 1982 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 Letter from applicant forwarding minutes of March 2 meeting.

March 23, 1982 Letter from applicant forwarding response to request for additional information regarding mimi-purge system valves.

March 24, 1982 Meeting with applicant to discuss alternate shutdown system and to review and discuss fire protection program.

March 31, 1982 Submittal of Amendment No. 9 to FSAR.

March 31, 1982 Letter from applicant transmitting Revision 5 to Security Plan.

April 2, 1982 Letter from applicant forwarding Revision 2 to 11 Environmental Qualification Report and Guidebook. 11 April 9, 1982 Letter from applicant transmitting processed marine seismic reflection lines.

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

April 9, 1982 Letter from applicant transmitting minutes of March 9 meeting on Seismic Qualification Review Team and Pump and Valve Operability Programs.

April 15, 1982 Generic Letter 82 Transmittal of NUREG-0909 Relative to the Ginna Tube Rupture.

April 16, 1982 Letter from applicant forwarding minutes of March 24 meeting.

April 16, 1982 Letter from applicant forwarding updated equipment list providing status of equipment availability for field inspect ion.

April 16, 1982 Letter to applicant advising that secondary water chemistry monitoring program is acceptable.

St. Lucie SSER #2 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 Generic Letter 82 Environmental Qualification of Safety-Related Electrical Equipment.

April 23, 1982 Letter to applicant forwarding requirements list for refer-ence material to be used to administer operator license examination.

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

April 27, 1982 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.

April 28, 1982 Letter from applicant regarding arrangement for storing facility records.

May 4, 1982 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 Meeting with applicant to discuss and resolve any open items on fire protection.

May 7, 1982 Letter from applicant forwarding information on handling of light loads.

May 11-14, 1982 NRC audit by Seismic Qualification Review Team and Pump and Valve Operability Review Team.

May 13, 1982 Letter from applicant forwarding construction/start-up progress report for April.

St. Lucie SSER #2 A-4

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

May 20, 1982 Letter from applicant transmitting revision to comments on Safety Evaluation Report.

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

May 24, 1982 Letter from applicant forwarding copy of test procedure utilized to verify Post Accident Sampling System Instrument-ation will function properly.

May 25, 1982 Meeting with applicant to discuss its response to IE Bul-letin 79-02 regarding base plate flexibility.

May 25, 1982 Meeting with applicant regarding safeguards program.

May 26, 1982 Submittal of Amendment 10 to FSAR.

May 26, 1982 Letter to applicant transmitting request for additional information.

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

June 7, 1982 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 asse~s 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 Meeting with applicant to discuss Technical Specifications.

June 16, 1982 Letter to applicant forwarding comments on Revision 5 of Security Plan.

St. Lucie SSER #2 A-5

June 16, 1982 Letter from applicant transmitting 11 QA Manual, 11 FPL-TQAR-100 Revision 5.

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

June 18, 1982 Letter from applicant forwarding construction/startup-progress report for May.

June 24, 1982 Letter to applicant transmitting request for additional information on emergency action levels.

June 25, 1982 NRC management preliminary review meeting.

June 30, 1982 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 Letter from applicant transmitting (1) minutes of meeting held on June 23 and (2) procedure for 11 Engineering Verifica-tion Program, 11 Revision 0.

July 12-16, 1982 On-site environmental qualification audit to review qualifica-tion documentation of safety-related equipment.

July 14, 1982 Letter from applicant forwarding (1) schedule for responding to open items and (2) responses to four open items.

July 15, 1982 Letter from applicant forwarding information on marine seismic investigation interpretation of processed data.

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

July 20, 1982 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 applicant 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 #2 A-6

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

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

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

August 2, 1982 Submittal of Amendment 11 to FSAR.

August 5, 1982 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 Pl an.

August 9, 1982 Submittal of Amendment 12 to FSAR.

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

August 13, 1982 Lette_r from applicant transmitting procedure for 11 Engineeriog Verification Program, 11 Revision 1.

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

August 17, 1982 Meeting with applicant to discuss staff comments on emergency operating procedures.

August 19, 1982 Letter from applicant advising of revised design of contain-ment isolation actuation signal.

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

St. Lucie SSER #2 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 Letter to applicant transmitting staff responses to comments by the applicant on the Safety Evaluation Report.

August 30- Instrumentation and Control Systems on-site audit, including September 3, 1982 plant tour to observe the installation of equipment August 31- Power Systems Branch on-site audit, including plant tour to September 3, 1982 observe installation of equipment.

St. Lucie SSER #2 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, Page 3-4, First Paragraph, Second Sentence Change 11 3 psi in 3 seconds" to 11 3 psi in 2 seconds" Section 3.5.3, Page 3-10, Third Paragraph, 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 condensate storage tank enclosure."

Section 3.9.3.1, Page 3-24, Fourth paragraph, 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, Page 4-1, Second Paragraph, First Sentence Change "and is designed" to "and is being licensed" Section 4.2.3.2(f), Page 4-17, Third Paragraph, First Sentence Change "Section 15.6.5 11 to "Section 15.10.3 11 Section 4.2.3.3(a), Page 4-17, Second Paragraph, First Sentence Change 11 Section 15.6.5 11 to "Section 15.10.3 11 Section 5.2.2.1, Page 5-3, First Paragraph, Second Sentence Change "licensed power level of 2570 MWt" to "licensed power level of 2560 MWt 11 Section 6.1.2, Page 6-2, Second Paragraph, First Sentence Change "ANSI 5.12 Protective Coatings (Paints) for the Nuclear Industry, American National Standards Institute.(1972), and ANSI 51.2 11 to "ANSI NlOl.4, Quality Assurance for Protective Coatings Applied to Nuclear Facilities, American National Standards Institute (1972) and ANSI N512 11 St. Lucie SSER 2 B-1

Section 6.1.3, Page 6-3, First Paragraph, Fourth Sentence Change 11 1480 kilograms 11 to 11 1665 kilograms 11 Section 6.2.1 2 Page 6-4. First Paragraph. Fourth Sentence Change 11 Annual 11 to 11 Annulus 11 Section 6.2.1.2, Page 6-7, Fourth Paragraph, Third Sentence Change 11 one of two air recirculation 11 to 11 two of four air recirculation 11 Section 6.2.3, Page 6-12, Second Paragraph, Second Sentence Delete 11 a recirculation fan 11 Section 6.2.5, Page 6-15, Second Paragraph, Third Sentence Change 11 provided for postaccident cleanup of the containment atmosphere 11 to 11 available for postaccident H2 purge of the containment atmosphere. 11 Section 6.3.2, Page 6-18, Fifth Paragraph, First Sentence Change 11 two motor-operated isolation valves" to 11 two (one-motor operated and one-solenoid operated) isolation valves 11 Section 6.4, Page 6-24, Fourth Paragraph, Second Sentence Change 11 the accident signal (safety injection) or the high gaseous radioactivity signal 11 to 11 a containment isolation actuation signal or a high radiation signal" Section 6.4, Page 6-24 2 Fourth Paragraph, Third Sentence Change 11 2000 cfm 11 t;o 11 1550 cfm 11 Section 6.5.2, Page 6-26, First Paragraph, Second Sentence Add 11 in the vicinity" after 11 is present" Section 6.5.2, Page 6-26, Third Paragraph, First Sentence Add 11 the vicinity of 11 after 11 open baskets in 11 Section 6.5.3, Page 6-26, Second Paragraph, Third Sentence Change 11 by means of dampers, from exhaust to recirculation within the shield building in order 11 to 11 by means of dampers and outside air makeup lines. 11 Section 6.5.3, Page 6-27, Third Paragraph, Fifth Sentence Change 11 initiation activation 11 to 11 isolation actuation 11 St. Lucie SSER 2 B-2

Section 8.2.1, Page 8-2, Sixth Paragraph, Third Sentence Change 11 the 4.16 kilovolt power to both St. Lucie Units 1 and 2 is paralleled to facilitate continued operation of both units. 11 to 11 the respective transformer of the unaffected unit is capable of supplying the required loads on both units. 11 Section 8.3.1, Page 8-5, Second Paragraph Delete second paragraph. The design of these tie breakers are such that this requirement is not necessary.

Section 8.3.1.1, Page 8-6, First Paragraph, Third Sentence Change 11 regulatory 11 to 11 regulator 11 Section 8.3.1.1, Page 8-6, Second Paragraph, Fifth Sentence Delete the word 11 four 11 Section 8.3.1.2, Page 8-8, Second Paragraph, Second Sentence Add 11 are generally" after 11 redundant load groups" Section 8.4.1, Page 8-12, First Paragraph, Sixth Sentence Delete the phrase 11 of appropiate color background 11 Section 8.4.1, Page 8-12, First Paragraph, Eighth Sentence Add the following eighth sentence in this paragraph: 11 In addition, appropriate color marks are provided for all equipment. 11 Section 8.4.2, Page 8-13, First Paragraph, First Sentence Change 11 detection of an emergency condition 11 to 11 buses on detection of a safety

injection signal on loss of offsite power. 11 Section 8.4.2, Page 8-13, Fifth Paragraph, First Sentence Change 11 to (1) disconnect 4 kilovolt loads on detection of a safety injection signal and (2) provide two isolation devices in series for those" to 11 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. 11 Section 9.4.1, Page 9-19, Second Paragraph, Second Sentence Change 11 safety injection signal 11 to "containment isolation actuation signal 11 and add 11 for recirculation mode 11 after 11 flow path 11 Section 9.5.3, Page 9-35, First Paragraph, Third Sentence Change 11 411 to 11 8 11 St. Lucie SSER 2 B-3

Section 10.3.4.3.f, Page 10-9, First Sentence Change 11 site 11 to 11 side 11 Section 10.4.1, Page 10-9, Third Paragraph, First Sentence Delete the phrase 11 reactor feedwater pump turbine" after 11 the main turbine and" Section 10.4.2, Page 10-10, First Paragraph, Second Sentence, Change 11 fogging 11 to 11 hogging 11 Section 11.2, Page 11-2, Second Paragraph, Third Sentence Delte the phrase 11 radwaste building" after 11 and auxiliary building" Section 11.4, Page 11-6, First Paragraph, Fifth Sentence Add 11 or adjacent to 11 after 11 are located in 11 Section 11.4, Page 11-6, First Paragraph, Sixth Sentence Change 11 cement 11 to 11 a solidification agent (e.g., cement or cement plus sodium silicate or dow binder)"

Section 12-3.4, Page 12-5, First Paragraph, Second Sentence Change 11 39 11 to 11 41 11 Section 14, Item #6 on Page 14-4 Delete the statement made in item #6 in its entirety and replace with the following: 11 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. 11 Section 15.1, Page 15-2, Table 15.1 Change 11 % of 2570 MWt + 18 MWt Rep input" to 11 % of 2560 MWt + 18 MWt Rep input" Section 15.5, Page 15-8, First Paragraph, Third Sentence Replace the entire third sentence to 11 If DNB occurs, cladding perforation should be assumed. 11 Section 15.10.1, Page 15-15, Tenth Paragraph, Second Sentence Change 11 a. DNBR below 1.19 11 to 11 the occurrence of DNB 11 Section 15.10.4, Page 15-20, First, Third, Fourth, Fifth and Sixth Paragraphs All references to the word 11 CESEC 11 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, Pages 15-35, 15-36 and 15-38, Tables 15.6, 15.7 and 15.9, under X/Q values Change 11 6.3 11 to 11 6.7 11 Section 15.11.7, Page 15-31, Second Paragraph, First Sentence Change 11 Table 15.3 11 to Table 15.5 11 Section 15.11.7, Page 15-31 Third Paragraph, First Sentence Change 11 Table 15.111 to 11 Table 15.3 11 Table 15.8, Page 15-37 Change 11 6.7 E-4 11 to 11 6.7 E-5 11 and 11 4.0 E-6 11 to 11 5.0 E-6 11 Table 15.9, Page 15-38 Change 11 6.3 E-5 11 to 11 6.7 E-5 11 Section 17.2, Page 17-1, Second Paragraph, Second Sentence Replace 11 five 11 by 11 four 11 ; add 11 and 11 after 11 Engineering and New Projects 11 ;

Delete 11 and St. Lucie 11 Section 17.2, Page 17-1, Second Paragraph, Third Sentence Delete the sentence and replace with 11 the Superintendent of St. Lucie - QA, who reports to the Director of Nuclear Affairs, has an onsite Staff. 11 Section 17.2 Page 17-1, Second Paragraph, Third Sentence Change 11 implementing 11 to 11 implementation 11 Section 17.5, Page 17-4, Under Regulatory Guides Change 11 1. 28 11 to 11 1. 811 Section 22.2, II.B.3, Page 22-5, Under 11 License Conditions, 11 Item e.

Change 11 24 days" to 11 4 days" Section 22.2, 1I.F.1(2d), Page 22-22, 11 Discussion and Conclusion, 11 First Paragraph, First Sentence Delete 11 not 11 Section 22.2, II.F.2, Page 22-24, Under "Saturation Margin Monitor" Change 11 0-300 psia 11 to 11 0-3000 psia 11 and change 11 100-1800°F 11 to 11 200-2300°F 11 St. Lucie SSER 2 B-5

Section 23, Page 23-1, Item (2) in the first paragraph Change 11 CPPR-103 11 to "CPPR-144 11 Section 23, Page 23-1, Second Paragraph, First Sentence Change 11 st. Lucie Steam Electric Station Unit No. 211 to 11 st. Lucie Plant, Unit No. 2. 11 Appendix C, Page C-20, Under "American Society of Testing Materials Specification."

Change 11 ASTM A522-70a 11 to 11 ASTM A572-70a 11 Appendix C, SSER #1, page C-2, Third Paragraph Delete entire third paragraph.

Appendix D, Page D-3 Delete: 11 LAl8 - Louisiana State Highway 18 11 11 LNED - Louisiana Nuclear Energy Division 11 11 LOEP - Louisiana Department of Public Safety, Office of Emergency Preparedness" 11 LP&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 v~ssel 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 (B&W) 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- 3 per reactor year that a B&W-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 #2 C-1

probability of such an overcooling event in CE- or W-designed reactors is lower, perhaps by an order or magnitude than for B&W-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 B&W-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 RTNnT. = 40°F and copper content of 0.35%) would be in the range of 10 19 neutroNS/cm. The highest neutron fluence to date in a B&W-designed facility is less than half the minimum value listed above. It would, therefore, be several years before any B&W-designed facility reached its threshold irradiation level.

Some reactor vessels in CE and Wfacilities 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~~Tlar 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 B&W-designed reactors, this probability is estimated to be about 10- 3 per reactor per year, and for W- 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 #2 C-2

APPENDIX D 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment 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 qualification program.

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 11 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 1.100, 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 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 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 below:

Generic Open 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 acceleration levels (G values) to which they are qualified.

St. Lucie SSER 2 D-1

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.

B. 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.

C. 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.

The applicant is committed to provide this information by 8/31/82.

D. 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 QC review of transformer mounting and re~ults of inspection by 7/30/82.

E. As to be mentioned in Specific Open Items, (k), below, during the field inspection of the 32 11 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.

F. 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.

Specific Open Items Provide clarifying details of open items as described below:

(a) Recorder No. M226S (NSSS-4).

St. Lucie SSER 2 D-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 SQRT 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 SQRT review by 8/31/82.

(e) 10 11 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 SQRT 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.

(g) 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.

(h) Signal Characterizer (NSSS-5).

The Foxboro cabinet where this signal characterizer is located does not have ID tag. The applicant is committed to provide confirmation of ID tag installation by 8/1/82.

(i) 211 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 SQRT review by 8/31/82.

(j) 12 11 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 SQRT review by 9/30/82.

(k) 32 11 MSIV, I-HCV-08-18 (BOP 1).

This valve was qualifie~ by analysis only. Based on past experience of the SQRT, 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 corrosion 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.

(1) 811 Gate Valve, Valve I-MV-08-14 (BOP 2).

This SQRT 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 SQRT 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 SQRT for review by 7/30/82.

(n) 4.16 kV Switchgear (BOP 11).

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 SQRT 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 (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 1 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 1 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.

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

1. 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 assure 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.

2. During the audit the applicant presented an overview of the Generation Equipment Management System (GEMS) which is a computer program to aid in the scheduling 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 (FP&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 prior 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.

Specific Concerns

1. Jamesbury 10 11 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, 1982.

In addition, as this valve is a throttling valve which will be used in the partially open 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.

2. Fisher Control, 111 Diaphragm-Operated Globe Valve V2650, BAMT Recirculation Isolation Valve The documentation package for this valve was also incomplete. Hydrostatic and leakage test data was not included. A copy of the hydro test data was provided to the staff on June 17, 1982.

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.

3. Fisher Controls, 111 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.

4. TRW Mission, 24 11 Check Valve, 21-V-7172, Containment Spray C~eck 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 11 x 32 11 x 34 11 Globe Valve, I-HCV-08-18, Main Steam Isolation Valve This is an air-operated, Y-type, bi-directional balanced stop valve. This valve serves two safety functions: (1) 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 1 s ability to close under full flow conditions prior to fuel load.

6. Byron Jackson, Intake Cooling Water Pump, ICW Pump 2A Seismic Qualification Review Team (SQRT) 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 SQRT 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.

We 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. Documentation 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 1 s program in a future supplement to the Safety Evaluation Report.

St. Lucie SSER 2 0-8

APPENDIX E REVIEW AND EVALUATION OF STATE AND LOCAL PLANS BY FEMA Federal Emergency Management Agency Washington, D.C. 20472 30 JUL 1982 MEMORANDUM FOR: Brian Grimes Director Division of Emergency Prepa~edness U ~uc~ S .R?¥ja~mission FROM: R*c rd w:ftri'J'mv1,v f-J\.

Assista t Associate Director Office of Natural and Technological Hazards

SUBJECT:

Interim Finding on Offsite Emergency Preparedness at St. Lucie Power Station, Florida The purpose of this memorandum is to transmit the Federal Emergency Management Agency (FEMA) Interim Finding on the St. Lucie Power Station, Florida. This finding is based on "draft plans" submitted by the State of Florida and an exercise of these plans held during the period February 10-12, 1982. The following material is attached:

1. Memo entitled "Florida (Plant St. Lucie) Interim Finding Report" from Regional Director, FEMA Region IV to the Associate Director for State and Local Programs and Support, dated July 6, 1982.

2. Letter from RAC IV Chairman to Director, Florida Division of Public Safety Planning and Assistance dated*February 25, 1982, listing deficiencies noted at the February 10-12, 1982, exercise.

3. Letter from Director, Florida Division of Public Safety Planning and Assistance to the RAC IV Chairman, dated May 25, 1982, responding to the deficiencies identified during the 1982 exercises at St. Lucie, Turkey Point and Crystal Riv~r nuclear power plants.

The FEMA Interim Finding, as stated by the Regional Director, FEMA Region IV, states that "while plan and plan execution improvements are needed, we consider the State of Florida and the involved counties to be capable of implementing their planned responses to an offsite release of radioactive material at the St. Lucie Power Station."

The State of Florida has recently contracted with a firm to revise the State and site specific plans to include SOP's and a draft will be submitted to FEMA Region IV by December 1, 1982. The RAC Review and Comments will be furnished Florida by February 15, 1983. The plan should be officially submitted by the Governor no later than March 31, 1983. Therefore, the schedule in Attachment 3 is void and the anticipated revised plan submittal date to FEMA Region IV is November, 1982, versus October, 1982, as stated in Attachment 1.

8208110107 820730 PDR ADOCK 05000335 F PDR E-1

2 Although the 11 Alert and Notification" system is in place, the adequacy of the system must be verified in accordance with NUREG 0654/FEMA REP-I.

If I can be of any further assistance on this matter, please contact me or Vern Adler at 287-0200.

Attachments as stated E-2

Federal Emergency Management Agency Region IV 1375 Peachtree Street, NE Atlanta, Georgia 30309 July 6, 1982 MEMORANDUM FOR: LEE M. THOMAS, ASSOCIATE DIRECTOR

~ -~J.i!AL PROGRAMS AND SUPPORT FROM: MaJ~/M?

Regional Director

SUBJECT:

Florida (Plant St. Lucie)

Interim Finding Report The enclosed report is submitted for your review as requested.

No corrections have been made to noted deficiencies and none is anticipated until October 1982.

While plan and plan execution improvements are needed, we consider the State of Florida and the involved counties to be capable of implementing their planned responses to an off-site release of radioactive material at the St. Lucie Power Station~

Enclosure E-3

I. INTRODUCTION The following Plant St. Lucie site-specific preliminary evaluation report is provided for FEMA National Office review. The 10-mile EPZ includes St. Lucie and Martin Counties. REP plans from these counties and the State. Bureau of Disaster Preparedness were reviewed to produce the findings of this report.

In addition, RAC IV conducted an evaluation of the St. Lucie exercise held during the period February l0-12, 1982.

II. EVALUATION The following evaluation relates to planning standards A through P, NUREG 0654/FEMA-REP-l.

A. Assignment of Res'P'?nsibility (Organizational Control)

During the exercise the transition from local control to State control was not clearly defined. Leadership at local and State EOC's hampered by frequent involvement in telephone conference line network. Counties involved did not have school system represented in response organization. Agreements should be negotiated which establish separate and mutual responsibilities of licensee and local governments regarding response operations.

B. On-Site Emergency Organization Applicable onlg to licensee.

c. Emergen91 Response Support and Resources Assistance available through the Florida Power Corporation contract with the University of Florida is not identified.

Also, it is not clear whether the university will work for the utility or the State during response. Facilities have not been completely identifed and agreements are not included in plans.

D. Emergency Classification System There are no clear cut provisions for the licensee to provide protective action recommendations to local officials.

E. Notification Methods and Procedures Official evaluation of the prompt notification system has not been accomplished.

F. Emergency Corrmrunications Alerting and notification of response personnel should be addressed more thoroughly. Means for 24-hour notice and particular information related to incident categories should be included in county plans.

E-4

During the exercise it was evident that point to point communications between the State and other facilities need to be improved. Installation of the planned ring down circuit would alleviate communications problems.

G. Public Education and Information There is no evidence that an annual public information dissemination program exists. Information materials and the means for distribution are not included in plans.

Physical accommodations at the FEOC were inadequate for media visitors.

No procedures were established to permit PIO and/or EOC director to respond spontaneously to media queries; clearance procedures were time-consuming. Rumor contxol centers were not established in affected areas.

H. Emergency Facilities and Eauipment County plans do not establish a central point for receipt and analysis of field monitoring data. Plans do not identify or describe emergency kits.

The plan does not make clear at which installation (SEOC, EOF, or field operations center) the command/control process will take place.

I. Accident Assessment Plans indicate a lack of capability to monitor radioactivity in stipulated ranges. If DOE is to provide this capability, a written agreement with DOE is appropriate.

J. Protective Response There are no provisions for the licensee to forward protective action recommendations to State response organizations.

The plan policy statement should be revised to indicate that KI is no longer a prescriptive drug. The State Health Officer is not included in the decision-making process relative to the use of radio-protective drugs.

County plans should reference the State plan relative to protective action guides. During the exercise it was observed that county protective actions for special populations were not addressed.

It was observed during the exercise that the procedures for administration and distribution ot KI were not clear at the FEOC.

K. Radiological ExPOsure Control It was observed that exposure control measures Eor emergency workers were inadequate at State and County facilities. Plan does not address the disposition of contaminated injured persons.

E-5

L. Medical and Public Health Support Lett:ers of agreement concerned wit:h transport:at:ion of injured do not contain language which assures that transportation will be made available.

M. Recovery and Reentry Planning and Post:-Accident Operations Decision-making process for reentrg and recoverg is not: made clear in plans.

Premature termination of exercise precluded the observation of recoverg and reent:rg operat:ions.

N. Exercise and Drills The February exercise was well conducted and observed, and ident:ified the need for additional training in most areas of emergency response at bot:h State and local levels.

o. Radiological Emergency Response Training Training for medical support: personnel not under contract: to the licensee is not speci:Eicallg provided for in the plans.

Exercise demonstrated that additional training is needed in the area of decontamination, dosimetrg and exposure control methodologg.

P. Responsibility for the Planning Effort:

No significant deficiencies noted.

III. SCHEDULE OF CORRECTIONS Florida indicates the plan improvements and corrections will be submitted to FEMA in October 1982.

- 3 -

E-6

Federal Emergency Management Agency Region IV 1375 Peachtree Street, NE Atlanta, Georgia 30309 February 25, 1982 Mr. Robert S. Wilkerson Director, Division of Public Safety Planning and Assistance 1720 Gadsden Street Tallahassee, Florida 32301

Dear Mr. Wilkerson:

Enclosed is a list of deficiencies concerning the Plant St. Lucie Exercise conducted during the period February 10-12, 1982. Although many specific items of the Exercise were observed to be proficient, only deficiencies are identified in the attached list for reviewing ease and corrective action.

In particular, the members of the Regional Assistance Committee (RAC) and FEMA regional staff gave high marks to the involved emergepcy response personnel for their overall enthusiasm and seriousness of purpose. The Exercise was certainly a successful one in that it adequately tested the State and local Radiological Emergency Preparedness Plans and revealed areas of proficiency and deficiency.

We are aware that, as a result of the Exercise and critique conducted for St. Lucie, revisions are possibly being made in the State and Site-Specific Plans*. Therefore, at the earliest convenience, please provide the FEMA Regional Director a report on how and when the noted deficiencies will be corrected. After receipt of this report, the process of plan review and acceptance may proceed.

We compliment the State of Florida on its excellent Radiological Emergency Preparedness effort and assure you that che RAC and FEMA staff are committed to the future support of these activities in your state.

Sincerely yours,

//~~.~}-

Glenn C. Woodard, Jr.

Chairman, *RAc IV Enclosure E-7

RADIOLOGICAL EMERGENCY PREPAREDNESS EXERCISE PLANT ST. LUCIE - FORT PIERCE, FLORIDA February 10-12, 1982 Deficiencies Observed by FEMA/RAC I. Emergency Operation Facilities and Resources (Working space, internal communications and displays, communications, security).

l. State EOC: Point to point communications between State and other faciliti-es need to be improved. Ring down circuit would alleviate information flow problems. Media center co-located with State EOC created problems.

2. FEOC: Internal communications system needs improvement; message circulation inadequate; status boards, charts and maps were not being kept current.

3. St. Lucie County EOC: Inadequate operating space and poorly designed structure. Internal flow of information was inadequate; message board not posted pro~ptly or accurately; sector map not delineated to show evacuation sectors; no population map.

4. Martin County EOC: Internal-communications inadequate; no oral briefings; security inadequate.

II. Alerting and Notification of Officials and Staff (Staffing, 24-hour capability, alerting timeliness)

1. Martin County EOC: Did not demonstrate provisions for 24-hour capability.

III. Emergency Operations Management (Organization, control, leadership, support by officials, information flow between levels and organizations, decision making, checklists and procedures).

1. FEOC: Transition from local control to State control was not clearly defined. Leadership was hampered by frequent involve-ment in telephone conference line network.

2. St. Lucie County EOC: Leadership hampered by frequent involvement in telephone conference line network. School system not represented in response organization. Operations room staff, at times, did not have clear picture of situation; i.e., staff, at 12:05 p.m.,

did not: reali=e that t:he EOC had be-=n moved to l1artin County at 11:30 a.m. Only one elected official present for Exercise (for 1/2 day).

E-8

page 2

3. Martin Countu EOC: Leadership hampered by frequent involvement in telephone conference line network. School system not represented in response organization.

IV. Public Alerting and Notification (Means of notification, e.g., sirens, vehicles, or other systems, notification timeliness).

1. Local Function: adequate V. Public and Media Relations (Publications, press facilities, media briefings, news release coordination) *

l. State EOC: Multiple sources of news releases created confusion.

2. FEOC: Physical accomm::,dations inadequate for media visitors.

Only one telephone and one typewriter available in one small room.

No procedures established to permit PIO and/or EOC Director to respond spontaneously to media queries without time-consuming clearance procedures with Tallahassee and with on-scene representa-tives. Rumor control centers were not established in affected areas.

3. St. Lucie County EOC: Exercise did not demonstrate public information functions at tire local level.

4. Martin County EOC: Exercis*e did not derronstrate public fU+Jctions information at the local level.

VI. Accident Assessment (Staff and field operations, rronitoring, adequacy of equipment, technical calculations, use of PAGs, issuance of timely recommendations).

l. State: MERL, while at Stuart, experienced communications problems with their radio frequency. MERL then switched to the LGR and seriously interferred with other response organizations' clear reception.

VII. Actions to Protect the Public (Sheltering, evacuation, reception and care, transportation).

l. FEOC: An extended delay was noted in announcing protective actions.

2. St. Lucie County EOC: Protective actions fer special populations, i.e., schools, hospitals, nursing homes, handicapped, were not addressed. The one reception center, in Indian River County, was deficient in that: the map indicating center l0cation was inaccurate; no signs were pos~ed on approach to reception center; one-lane dirt roads ran through the center grounds; no plan E-9

page 3 was evident for providing clothing to those persons decontaminated; procedures for processing evacuees not well organized; no equipment available for vehicle decontamination; no containers available for personal clothing; and initial checkpoint needed a recorder.

3. Martin County EOC: Protective actions for special populations were not addressed.

VIII. Health, Medical, and Exposure Control Measures (Access control, adequacy of equipment and supplies, dosimetry, use of KI, decontamination, medical facilities and treatment).

1. State EOC: The order to issue, and the administration of, KI was not made clear to State EOC staff.

2. FEOC: Administration and distribution of KI procedures were not clear. Exposure control procedures for monitoring team were inadequate.

3. St, Lucie Cqunty EOC: Although the Sheriff's Department had a system for determining dosage and had record forms, there was no overall system of exposure control measures for the county's emergency workers.

4. Martin County EOC: Measures for effective exposure control for emergency workers were inadequate. A log book for recording the dosage of workers was not observed. Appropriate ?ction levels for determining need for decontamination were not specified.

Measures for decontamination of emergency personnel and equipment, and for waste disposal, were inadequate.

IX. Recovery and Reentry Operations

1. State: Premature termination of Exercise precluded the observation of recovery and reentry operations.

2. Local : Same comment as above.

X. Relevance of the Exercise Exoerience (Benefit to participants, adequacy of scenario).

The purpose of the Exercise was accomplished; however, scenario did not stress importance of terminating Exercise only after all phases, including recovery and reentry, had been completed.

Questionnaires retur~ed by Exercise participants indicated that the Exercise was very worthwhile and provided a basis for improvement of response capability.

E-10

~ ... I, BOB GRAHA~t Gvvemor JOAN M. HEGGE.'J Secrec:u; Director May 25, 1982 Mr. Glenn Woodard, Jr.

Federal Emergency Management Agency, Region IV 1375 Peachtree Street, Northeast Atlanta, Georgia 30309

Dear Glenn:

This letter is in response to FEMA and RAC deficiencies identified during the recent exercises at the St. Lucie, Turkey Point, and Crystal River nuclear power plants. Attachment I outlines state and 1ocal efforts to correct identified deficiencies. Attachment II is our proposed workplan for the completion of radiological emergency management activities through June 1983.

On April 28, Bureau of Disaster Preparedness staff met with repres~ntatives from both utilities and the Department of Health and Rehabilitative Services to discuss revisions to plans and SOP's, contract status, and annual exercise requirements. Bureau staff requested that the utilities provide additional resources (both short and long-term) to assure the timely completion of those activities specified in the two attachments. If this request is denied or partially granted, Bureau staff will submit a request for an extension and a revised workplan to reflect more realistic completion dates.

I will keep you advis~d of our progress toward the compl!tion of those activities specified in the attachments. If you have any questions or require additional information, please contact Mr.

Gordon Guthrie.

Sincerely,

~ -..... l Robert S. Wilkerson ....*-**-**-\ :.1 Director i

. ' *.~. .

.... I

\

RS~I/BN/db ...-*--*-\ .

Attachments (2) f\:n F\(\-\ t<\~~ ROOM 1 3 OFFICE OF THE DIRECTOR

. \. *-* .... --

--->.*=**:::,:}_

53C CARLTON BUILDING

TALLAHASSEE, FLORIDA 32301 (904) 4S8-6C0l E-11

ATTACHMENT I RESPONSE TO CRITIQUE DEFICIENCIES I* Emergency Operations Facilities and Resources Point to point communications between the state EOC and other facilities will be improved through the purchase and installation of the hot ring down system, single sideband radio network, and a hard copy system with the capability to transmit technical data to all emergency facilities. The hot ring down system is a dedicated phone line network linking the state EOC, FEOC's, EOF's, power plant control rooms, risk counties, and DHRS Radiological Health Services. System specifications have been devel-oped and approved by the Florida Division of Communica-tions. Southern Bell reports that activities have begt1n to install the hot ring down system, and it is expected to be fully operational by the end of May 1982.

The single sideband radio network will serve as a back-up to the hot rtng down system and will *connect the same points. System specifications have been developed and approved by the Florida Division of Communications.

Application for licenses have been developed and submitted to the FCC for their consideration. It is anticipated that the earliest date for license approval will be July or August 1982.

To facilitate point to point communications of technical data (i.e., plant parameters, dose assessments, dose projections), a working committee made up of state, risk county, and utility representatives has been formed to consider the requisite capabilities of a high-speed hard copy transmission system. The working committee is currently conside~ing proposals to assess hard copy transmission needs and to develop specifications for this system.

In addition to hard copy needs, the working committee is also examining communications needs, emergency news center (ENC) operation, and emergency facility locations.

With regard fo emergency facility locations, the working committee is examining possible locations for the media

center that will be outside the State EOC. The committee is also examining possible alternate locations and options for field emergency operations centers (FEOC's) for the Crystal River and St. Lucie plants. One option under con-sideration is a mobile FEOC that could be transported to berthing stations near each plant.

E-12

Florida Power and Light Company (FPL) has agreed .to fund a feasibility study for the planning, location, and design of a new EOC for St. Lucie County. Further funding for the construction of a new EOC will be contingent upon the results of this and other facility studies. BOP staff will work with Dade and St. Lucie counties to assure that adequate'visual aids for displaying evacuation routes, relocation centers, and population by sectors are available. Funding for the communications improvements required at the Monroe County EOC will be provided as a result of negotiations with FPL, which are tentatively scheduled for October. The working committee will examine working space problems at the Monroe County EOC and make appropriate recommendations for improvements.

The working space problems identified at the Citrus County EOC should be resolved upon the identification of a suitable location for the FEOC by the working committee.

The Levy County Commission has agreed to make space available to relocate their EOC, thus improving EOC working space and conditions. BOP staff have scheduled the development of training standards, revision of SOP's, and training sessions prior to the next exercise. These activities should improve EOC internal communications and information flow, record keeping, and overall operation.

II. Alertina and Notification of Officials and Staff Funding has bee~ provided by FPL to Martin County for tr~ining local emergency response personnel and public officials. This training should assure that Martin County dem*Jnstrates a 24-hour capabi 1 ity to manage and respond to a radiological emergency.

III. Emerq~ncy Operations Management BDP staff is currently involved in the revision of th2 plan to more clearly define direction and control during an emergency. The revision to this section of the plan is scheduled for completion in May.

The installation of the hot ring down system will elimi~-

ate facility managers' involvement in the telephone con-ference line network. BOP staff has scheduled the revis-ion of EOC alert, notification, staffing, .and operations SOP's for Martin and St. Lucie counties to include the school system in the response network and to improve internal commun*ications and information flow.

The working committee will also examine the function and operation of the emergency news center (E~C) to assure that timelv and accurate information is disseminated. The committee 1s also examining additional technical (DHRS)

E-13

staff requirements at the EOF. The additional technical staff will improve coordination between DHRS and the Governor's Authorized Representative {GAR). SOP's for the activation, staffing, and operation of the EOF are sched-uled for revision to assure improved coordination and management of EOF activities.

IV. Pub~ic Alerting and Notification The installation of the hot ring down system will assure that important information (i.e., changes in plant status/

parameters) will be received by all points on the system si:nultaneously, and should minimize delays in announcing important imformation.

BDP staff is in the process of revising the notification annexes of the state and site plans. These revisions will result in standardized notification forms and procedures (where possible). Additional cross-training will be sched-uled in Levy County to assure that adequate resources are available for effective dissemination of notification information.

V. Public and Media Relations The working committee and BOP staff have scheduled the revision of the ENC concept to identify s~ecific respon-sibilities of state, local, and utility Public Information Officers (?!O's); establish procedures for the accurate and timely dissamination of information; and assure effec-tive management of public information. In addition, all SOP's for ~!O's have bean scheduled for revision prior to the next exercise.

The working committee is also examining the issue of relo-cating the FEOC for the St. Lucie plant. A suitable relo-cation of the FEOC would include adequate physical accom-modations for-media visitors.

BDP staff is in the process of rev1s1ng information brochures and posters for distribution to Citrus and Levy c o u n t i e s

Th e s e po s t er s an d br o c h u t* e s wi l 1 ad v i s e r e s i -

dents as well as transients of actions to take in the event of a radiological emergency. BOP staff will propose radiological emergency procedures for inclusion in the Crystal River area phone book. BOP staff will work with Citrus and Levy counties to develop overlays identifying geographic areas that closely corr~spond to each popula-tion sector. A slide/tape presentation is being developed for public and media education.

Florida Power Corporation (FPC) has scheduled the construction of a new EDF, which will include adequate physical accommodations for the media. This new facility is to be contructed by October 1982 and fully equipped by March 1983.

VI. Accident Assessment DHRS staff is in the process of examining their com-munications needs to assure that the MERL and field moni-toring teams are adequately equipped to transmit and receive accurate and timely data, and to allow the MERL to effectively monitor communications with field monitoring teams. DHRS is also examining the issue of requisite staffing for the MERL to assure more effective deployment and management of field monitoring teams. The SOP's per-taining to the operation of the MERL will then be revised to address these issues, as well as MERL security, decon-tamination of returning field monitoring teams, periodic briefings of field monitoring teams, policy(ies) for withdrawal from contaminated areas, and standardized checklists for logging data transmissions.

Additional funds for needed communications equipment for the MERL and field monitoring teams and updated maps will be negotiated as an addendum to existing contracts or as line items in the new contracts under the orovisions of HB 1066. This legislation amended Chapter ~52, Florida Statutes, to establish respective roles in the develop-m2nt, testing, implementation, and funding of radiological emergency plans and preparedness. DHRS will also negotiate additional health physicist positions to assure an ade-quate response capability. Ins~allation of the hot ring down system and the hard copy system for the transmission of technical data will assure that radiological safety officers in the FEOC's have the cap~bility to receive and transmit data regarding plant status and parameters, and offiste dose assessments and projections.

~PC has scheduled the contruction of a 26,000 square feet EOF n e a r th e a i r p o r t , a p p r a x i ma t e l y 1 0

1 mi 1 e s f_r om the plant site. Construction is scheduled for completion in October, and the facil*ity should be fully equipped by March 1983. FPC staff has expressed a desire to meet

\*ii t h BDP/ DHRS s t a ff re g a r d i n g t h e f 1 o o r p l a n an d 1 a yo u t to assure the co-location and coordination (i.e., standard forms) of state and utility dose projection personnel.

VII. Actions to Protect the Public Training standards are being scheduled for development for shelter management staff. BOP staff will work 11ith county 1 directors to develop a training curriculum to assure that E-15

shelter managers and staff are adequately trained to open and operate reception centers and shelters. SOP's for the activation and operation of reception centers and shelters will be revised or developed as needed. These activities should correct those shelter deficiencies identified in Citrus, Levy and Indian River counties.

In addition, the working committee i~ examining the ade-quacy of existing emergency facilities. For those recep-tion centers and shelters that cannot be modified to cor-rect those identified deficincies, new locations for these facilities will be recommended and equipped.

BOP staff is currently in the process of applying for user numbers to access OHRS and Florida State University com-puters to collect and analyze census data. Of primary interest is updated population figures for schools, hospi-tals, nursing homes, and other special facilities in areas surrounding nuclear power plants. Accurate population data are prerequisites for the development of valid pro-tective actions for special needs populations.

FPL and FPC have provided funds to host counties for the purc~ase of disposable clothing/gowns for contaminated evacuees. Any equipment necessary for vehicle decon-tamination, disposal of contaminated clothing, or the effi-cient operation of rec~ption centers and shelters that is not currently available will be negotiated with the utili~

ties as an addendum to existing funding contracts or as line items in the new contrcts under the provisions of HB 1066. BOP staff has scheduled the develoment and adminis-tration of a needs assessment instrument to determine additional funding and resource needs of state and local agencies.

VIII. Health, Medical, and Exposure. Control Measures OHRS is in the process of developing an SOP for the pre-positioning of potassium iodide (KI), based on population densities surrounding each power plant, to provide guidance to the counties on storage and distribution of KI. DHRS has also revised the policy for the authoriza-tion to distribute and use KI. This policy will be included in the revised radiological emergency plan, and will request that each risk county health unit develop detailed plans for the issuance of KI.

BOP staff has scheduled the development cf training stan-dards for radiological instrumentation and exposure control. Once these have been developed, training sessions will be scheduled to improve record keeping, decontamina-tion procedures, and overall exposure control procedures for emergency personnel. Tl1e Florida Public Service Cpm1nission h~s provided funding for the BOP to contract E-16

with the University of Florida Department of Environmental Engineering for the provision and maintenance of ther-moluminescent dosimeters (TLD 1 s) for emergency workers.

Under the provisions of this contract (which is currently being reviewed by Department legal staff) the University would also maintain permanent dose records for emergency workers. ln addition, all SOP's regarding decontamination of emergency vehicles, radiological safety officers' responsibilities, field monitoring, decontamination of evacuees, radiological injuries, and radiological exposure control have been scheduled for revision.

I X* Recovery and Reentry Ooeration No response required.

X. Relevance of the Exercise Experience No response fequired.

E-17

APPENDIX F PRINCIPAL CONTRIBUTORS V. Nerses Project Management J. Lee Project Management A. Brauner Siting analysis J. Fairobent Accident evaluation (meteorology)

T. Cardone Geology R. Wescott Hydrology H. Polk Structural engineering J. Rajan Mechanical engineering T. Chang Seismic qualification M. Haughy Operability qualification of pumps and valves D. Powers Core performance C. Liang Reactor systems R. Stevens Instrumentation and controls J. Ridgely Auxiliary systems J. Stang Fire Protection S. Elrod Management and technical support organization D. Perrotti Emergency planning R. Skelton Physical security D. Hoffman Technical specifications J. Gilray Quality assurance J. Peterson Financial qualifications W. Kennedy Procedures and test review F. Witt Postaccident sampling Gage Babcock Brookhaven National Lab.

EG&G Battelle Pacific Northwest Laboratories St. Lucie SSER #2 F-1

NRC FORM 335 1. REPORT NUMBER {Assigned by DDCJ U.S. NUCLEAR REGULATORY COMMISSION (7-77)

NUREG-0843 BIBLIOGRAPHIC DAT A SHEET Supplement *No. 2

4. TITLE ANO SUBTITLE (Add Volume No., if appropriate} 2. (Leave blllflk}

Safety Evaluation Report Related to the Operation of St. lllcie PJ..ant Unit No. 2 3. RECIPIENT'S ACCESSION NO.

Docket No. 50-389

7. AUTHOR(S) 5. DATE REPORT COMPLETED MONTH I YEAR September 1982

9. PERFORMING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code} DATE REPORT ISSUED I YEAR u.s. Nuclear Regulatory Commission MONTH September 1982 Office of Nuclear Reactor Regulation 6. (Leave blank}

Washington, D.C. 20555 B. (Leave blank}

12. SPONSORING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code}

10. PROJECT/TASK/WORK UNIT NO.

Same as 9. above

11. CONTRACT NO.

13. TYPE OF REPORT I PERIOD COVERED (Inclusive dates}

15. SUPPLEMENTARY NOTES 14. (Leave blanAJ Docket No. 50-389

16. ABSTRACT (200 words or less}

Supplement No. 2 to the Safety Evaluation Report for the application filed by Florida Power & Light Company for a license to operate the St. lllcie Plant, Unit No. 2 (Docket No. 50-389), located in St. lllcie County, Florida has been prepared by the Office of Nuclear Reactor Regulation of the Nuclear Regulatory Commission. The

~pose of this supplement is to update the Safety Evaluation Report by providing our evaluation of additional information submitted by the applicant since Supple-ment No. 1 was issued and (2) our evaluation of the matters the staff had under review when Supplement No. 1 was issued.

17. KEY WORDS AND DOCUMENT ANALYSIS 17a. DESCRiPTORS 17b. IDENTIFIERS/OPEN-ENDED TERMS

18. AVAILABILITY STATEMENT 19. SECURITY CLASS (This report} 21. NO. OF PAGES Unclassified Unlimited 20. S1fiU~TY Cl,.1$ f[f1spageJ 22. PRICE nc assi ie s NRC FORM 335 17 77)

UNITED STATES FIRST-CLASS MAIL POSTAGE & FEES PAID NUCLEAR REGULATORY COMMISSION USNRC WASHINGTON, D.C. 20555 WASH. D C.

PERMIT No .kil.

OFFICIAL BUSINESS PENALTY FOR PRIVATE USE, $300

ML19115A335

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Dear Mr. Wilkerson:

Dear Glenn:

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Dear Glenn:

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