ML19115A339

NUREG-0843, Supplement 3, Safety Evaluation Report Related to the Operation of St. Lucie Plant, Unit 2.

ML19115A339
Person / Time
Site:	Saint Lucie
Issue date:	04/22/1983
From:	Office of Nuclear Reactor Regulation
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NUREG-0843 S3
Download: ML19115A339 (164)

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NUREG-0843

-~Sii'B1' i,t!BRAR'i Suppleme,to. 3 APR 2 2 1983 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 April 1983

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NUREG-0843 Supplement No. 3 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 April 1983

4/6/83 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 . . . . . . . 1-2 1.13 Nuclear Waste Policy Act of 1982 . . . . . 1-3 1.14 Engineering Verification Program (EVP).

I 1-4 2 SITE CHARACTERISTICS . . . . . 2-1 2.1 Geography and Demography 2-1 2.1.3 Population Distribution 2-1 3 DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3-1 3.5 Missile Protection . . 3-1 3.5.3 Barrier Design Procedures. 3-1 3.8 Design of Category I Structures . '* 3-1 3.8.4 Other Category I Structures 3-1 3.9 Mechanical Systems and Components . 3-2 3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core Support Structures. . . . . 3-2 3.9.6 lnservice Testing of Pumps and Valves . . . . . 3-3 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment. . . . . . . . . 3-4 3.10.1 Seismic and Dynamic Qualification - Introduction 3-4 3.10.2 Operability Qualification of Pumps and Valves . . 3-10 3 .11 Envi ronmenta 1 Qua 1 ificat ion of Safety-Re l_ated Equipment 3-15 3.11.1 Introduction . . . . . . . . . 3-15 3.11:2 Background . . . . . . . . . . 3-15 3.11.3 Staff Evaluation . . . . . . 3-16 3.11.4 Qualification of Equipment . . 3-20 3.11.5 Conclusions . . . . . . . . . 3-22 St. Lucie 2 SSER 3 iii

TABLE OF CONTENTS (Continued)

Page 4 REACTOR . . . . . .... ..... ' 4-1 4.2 Fuel System Design ***. 4-1 4.2.3 Design Evaluation .. . . . . .. 4-1 4.2.5 Evaluation Findings 4-5 4.4 Thermal-Hydraulic Design . 4-6 4.4.3 Design Abnormalities .* 4-6

. 4.4.4 Loose Parts Monitoring ** 4-6 4.7 References . . . * . . . * . . . . 4-6 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS *. 5-1 5.2 Integrity of Reactor Coolant Pressure Boundary 5-1 5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing. . .*.... 5-1 5.4. Component and Subsystem Design .. 5-2 5.4.3 Shutdown Cooling (Residual Heat Removal) System. 5-2 6 ENGINEERED SAFETY FEATURES. 6-1 6.2 Containment Systems; 6-1 6.2.4 Containment Isolation System .* 6-1 6.3 Emergency Core Cooling System. 6-2 6.3.2 Evaluation . . * . * . . 6-2 6.3.3 Testing . . . . . , . . . . 6-2 6.4 Control Room Habitability . . . . . . . . . . . . 6-3 6.6 Inservice Inspection of Class 2 and 3 Components 6-4 7 INSTRUMENTATION AND CONTROLS .. 7-1 7.1 Introduction . * . 7-1 7.1.5 Site Visit .. 7-1 7.2 Reactor Protection System. 7-1 7.2.5 Logic Matrix and Logic Matrix Power Supplies. . 7-1 7.3 Engineered Safety Features Actuation System. 7-1 St. Lucie 2 SSER 3 iv

TABLE OF CONTENTS (Continued)

Page 7.3.3 Auxiliary Feedwater System 7-1 7.3.6' Containment Isolation .. 7-2 8 ELECTRIC POWER SYSTEMS .* . * * . . . 8-1 8.1 General . . * . . . . * . . . . . . . * . *. 8-1 8.3 Onsite Emergency Power System. 8-2 8.3.1 Alternating Current Power System .. 8-2 8.3.2 Direct Current Power System . . . . . 8-3 8.4 Other Electrical Features and Requirements for Safety. . 8-4 8.4.1 Physical Identification and Independence of Redundant Safety-Related Electrical Systems . . 8-4 8.4.2 Nonsafety Loads on Emergency Power Sources. . . 8-5 8.4.3 Containment Electrical Penetrations.* . . . . * . . 8-5 8.4.6 Adequacy of Station Electric Distribution System Voltages. * . . . . . . . . . . . . 8-6 9 AUXILIARY SYSTEMS * . . . . . 9-1 9.1 Fuel Storage Facility. 9-1 9.1.3 Spent Fuel Pool Cooling and Cleanup System (Fuel Pool System). . . . . . . * . . . . . . . . 9-1 9.1.4 Fuel.Handling System. . *. 9-1 9.5* OthJr Auxi 1i ary Systeins .* . . ..  ; 9-2*

9.5.1 Fire Protection . . . . . . . . . .. . . . . .. . . 9-2 9.5.2 Communications Systems . . . . . * ...

• 9-16 9.5.4 Emergency Diesel Engine Fuel Oil Storage and_Transfer System. . . . . . . . . . .. . : . . . . . . .

I ~ 9-17 9.5.7 Emergency Diesel Engine Lubricating Oil System. 9-17 9.6 References . . . * . . . ..... 9-17 10 STEAM AND POWER CONVERSION SYSTEM .. 10-1 10.2 Turbine Generator . . . . . . . 10-1 10.2.1 Turbine Disc Integrity ** 10-1 10.3 Main Steam Supply System * . * * * . . .. . . .. 10-1 10.3.4 Secondary Water Chemistry .* 10-1 10.4 Other Features of the Steam and Power Conversion System. 10-1 10.4.7. Cond~nsate and Feedwater System. .. ... ... ..

, I*

10-1 St. Lucfe 2 SSER 3 V

TABLE OF CONTENTS (Continued)

• 11 RADIOACTIVE WASTE MANAGEMENT SYSTEM. . . . . . . . . . i~ 11-1 11.2 Liquid Waste Management . . . . . . . . . . . . . 11-1 11.5 Process and Effluent Radiological Monitoring and Sampling Systems . . . 11-2 13 CONDUCT OF OPERATIONS . 13-1 13.3 Emergency Planning . 13-1 13.3.2 Evaluation of the Emergency Plan . . . . . . . . . 13-1 13.3.3 Review and Evaluation of State and Local Plans by Federal Emergency Management Agency (FEMA) 13-1 13.3.5 Conclusions. . 13-1 13;6 Physical Security Plan 13-2 14 INITIAL TEST PROGRAM 14-1 15 ACCIDENT ANALYSIS .. 15-1 15.6 Reactivity and Power Distribution Anomalies. 15-1 15.6.3 Inadvertent Boron Dilution . 15-1 15.10 Limiting Accidents. . . . . . . . 15-2 15.10.2 Feedwater System Pipe Breaks 15-2 15.10.4 Steam Generator Tube Rupture . . . . . . . . . . . 15-4 15.10.5 Inadvertent Opening of a Pressurizer Relief Valve. . 15-5 15.11 Radiological Consequences of Design Basis Accidents. 15-6 15.11.5 Loss-of-Coolant Accident (Radiological

• Considerations). 15-6 22 TMI-2 REQUIREMENTS . . . . . . . . 22-1 22.2 Discussion of Requirements . 22-1 APPENDICES A CONTINUATION OF CHRONOLOGY*OF RADIOLOGICAL REVIEW. A-1 B PRINCIPAL CONTRIBUTORS . . . . . . . . . . . . . . B-1 C PSI RELIEF REQUEST EVALUATION. . . . . . . . . . . C-1 D EQUIPMENT REQUIRING REPLACEMENT PRIOR TO PLANT STARTUP . . . . . D-1 E EQUIPMENT REQUIRING ADDITIONAL INFORMATION OR CORRECTIVE ACTION. . E-1 F EQUIPMENT CONSIDERED ACCEPTABLE OR CONDITIONALLY ACCEPTABLE. . . . F-1 G SAFETY-RELATED SYSTEMS IN THE ENVIRONMENTAL QUALIFICATI'ON PROGRAM. G-1 H INSTRUMENTATION AND CONTROL SYSTEM BRANCH TRIP REPORT. . . . . . H-1 St. Lucie 2 SSER 3 vi

APPENDICES (Continued)

Page I FEMA STATUS UPDATE FOR ST. LUCIE 2 . . . . . . . . . . . . . I-1 J LETTER FROM DEPARTMENT OF ENERGY REGARDING SECTION 302(b) OF THE NUCLEAR WASTE POLICY ACT OF 1982. . . . . . . . . . . . . . J-1 LIST OF TABLES

~-1 Fire Protection Items to be Completed By 5% Power. 9-18 15-1 Revised Loss-of-Coolant Dose Consequences 15-8 15-2 Revised Loss~of-Coolant Dose Assumptions .. 15-8 St. Lucie 2 SSER 3 vii

1 INTRODUCTION ANO 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.

Supplement No. 2 (SSER 2) was issued in September 1982. In the SER, SSER 1, and SSER 2, the staff identified certain issues where either further informa-tion 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 2 to the SER was issued and (2) our evaluation of the matters the staff had under review when the SSER 1 and SSER 2 were issued.

Each of the following sections of this supplement is numbered the same as the section of the SER, SSER 1, and SSER 2 that is being.updated, and unless other-wise noted, the discussions are supplementary to and not in lieu of the discus-sion in the SER, SSER 1, and SSER 2. Appendix A to this supplement is a con-tinuation of the chronology. Appendix Bis the list of principal contributors to the staff review. Appendix C is the PSI relief request evaluation. Appen-dix Dis equipment requiring replacement prior to plant startup. Appendix Eis equipment additional information or corrective action. Appendix Fis equipment considered acceptable or conditionally acceptable. Appendix G is safety related systems in the environmental qualification program. Appendix His the Instru-mentation and Control System Branch site visit trip report. Appendix I is the FEMA status update for St. Lucie 2. Appendix J is a letter from the Department of Energy regarding Section 302(b) of the Nuclear Waste Policy Act of 1982. The NRC project manager for St. Lucie 2 is Mr. Victor Nerses. Mr. Nerses may be contacted by calling (301) 492-7000 or writing, Division of Licensing, U.S.

Nuclear Regulatory Commission, Washington, D.C. 20555.

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 qualification (3.10.1)

(2) Pump and valve operability assurance (3.10.2)

(3) Environmental qualifications (3.11) becomes a license condition (4) Fuel handling system light loads (9.1.4)

(5) Fire protection (9.5.1) becomes a license condition St. Lucie 2 SSER 3 1-1

1.8 Confirmatory Issues At the time of the SER issuance there were several issues which were essentially resolved to the staff's satisfaction, but for which certain confirmatory infor-mation had not yet been provided by the applicant. Since that time, the staff has reviewed this information and has confirmed the preliminary conclusions for most of the items. For the other items the confirmation will not be provided

. until after core load. These issues are listed below with appropriate references to subsections of this report. *

(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)), (g} becomes a license condition (6) Rod bowing (4.2.3.1 (f))

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

{8) Fuel rod mechanical fracturing (4.2.3.2(g))

(9) Seismic and LOCA loads (4.2.3.3(d)}

(10) Loose parts monitoring (4.4.4)

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

(12) 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)

(13) Boron mixing test results (5.4.3) becomes a license condition.

(14) Natural circulation cooldown tests (5.4.3) becomes a license condition (15) Upper head voiding (5.4.3)

(16) Sump vortex test {6.3.3)

(17) Start-up channel flux alarms (15.6.3)

'(18) Feedwater system pipe breaks (15.10.2)

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

(20) Inadvertent opening of PORV (15.10.5)

(21) Control Room Design Review (I.D.1) becomes a license condition 1.9 License Conditions Section 1,9 of the SER contained a list of license conditions. This supplement addresses the resolution of some of these conditions. This is listed below,

• along with the section of this report wherein the resolution is discussed.

(1) Population distribution (2.1.3) .

(2) Structural modifications due to ductility factor reanalysis results (3.5.3) *

(3) High burnup fission gas release (Fragmentation of embrittled cladding, 4.2.3.3(a)) ~

(4) Low flow alarms on safety i~jection pumps (6.3.2)

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

(6) Second fuel pool heat exchanger (9.1.3)

(7) Sound powered telephone system (9.5.2.10)

(8) Diesel generator lube oil modifications (9.5.7)

St. Lucie 2 SSER 3 . 1-2

(9) Turbine disc integrity (10.2.1)

(10) Secondary water chemistry (10.3.4)

(11) Water hammer testing (10.4.7)

(12) Emergency preparedness (13.3.3)

(13) Safety parameter display system (Section 22, I.D.2)

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

(1) Environmental qualifications (3.11)

(2) Axial growth (4.2.3.l(g))

(3) Inservice inspection program for Class 1, 2 and 3 components (5.2.4, 6.6)

(4) Natural circulation cooldown and boron mixing test (5.4.3)

(5) Containment ventilation system *minipurge valves (6.2.4)

(6) Barrier for high energy equipment (8.4.1)

(7) Non-safety loads on emergency power sources (8.4.2)

(8) Containment electrical penetrations (8.4.3)

(9) Heavy Loads (9.1.4)

(10) Fire protection (9.5.1)

(11) Emergency diesel engine'auxiliary support systems (9.5.4.1)

(12) Radioactive waste management (a) Refueling water storage tank level indication (11.2)

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

(c) Continuous oxygen analyzer (11.5)

(13) Initial test program (14)

(14) NUREG-0737 conditions (a) Control room design review (Section 22, I.D.1)

(b) Reactor coolant system vents (Section 22, II.B.1)

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

(d) In-containment High Range Radiation Monitor (Section 22, II.F.1(2c)) .

(e) Inadequate Core Cooling Instrumentation (Section 22, II.F.2) 1.13 Nuclear Waste Policy Act of 1982 Section 302(b) of the Nuclear Waste Policy Act of 1982 states that NRC shall not issue or renew a license for a nuclear power reactor unless the utility has signed a contract with the Department of Energy (DOE) for disposal services, or the Secretary of Energy affirms in writing that a utility is actively and in good faith negotiating with DOE for a contract. FP&L has provided the staff with a copy of their January 18, 1983 letter to DOE comment-ing on the propo?ed contract for disposal *of spent nuclear fuel and/or high level radioactive waste. In addition, this letter documented FP&L's intention to execute the required agreement with DOE as specified in Section 302(b) of the Nuclear Waste Policy Act of 1982.

St. Lucie 2 SSER 3 1-3

On February 11, 1983 (see Appendix J), the Secretary of Energy certified to the Commission that the licensee is actively and in good faith negotiating

. with DOE for a nuclear waste disposal contract.

1.14 Engineering Verification Program {EVP)

On January 10, 1983, FP&L formally submitted a report of their completed EVP on St. Lucie 2. The EVP consists of an independent generation*of designs for eight components which were subsequently compared to the.actual component designs that were installed in the plant. This independent work was performed by a task force of experienced CE and EBASCO engineers who had no prior involvment in the design, installation and testing of the components chosen. The eight components were randomly selected from a list of safety-related candidate components.

Agreement of the independent designs with the actual designs was the task force's means of confirming that design, procurement, construction, and installation is in accord with good engineering practices. The task force reported .that no major problems were found.

The FP&L submitted report is currently under staff review and the results of our preliminary:review indicate that it is ~cceptable. Therefore, the staff finds no reason to preclude St. Lucie 2 from operating up to 5% of rated thermal power. Prior to exceeding 5% of rated thermal power, the staff's completed detail review will be reported as part of the SER supplement for the full power amendment.

St. Lucie 2 SSER 3 1-4

2 SITE CHARACTERISTICS 2.1 Geography and Demography 2.1.3 Population Distribution In Supplement 1 to the SER we stated that the staff will require the applicant to periodically obtain and submit to NRC the actual and projected population around the St. Lucie site in order to determine what additional measures, if any, should be undertaken to assure the public health and safety. The appli-cant agreed with this requirement.

The staff initially considered this as an item for which a condition would be included in the operating license to ensure that NRC requirements are met during plant operation. Subsequently, the staff decided that this item's periodic requirements can be met appropriately and equally by including it in the Tech-nical Specification (TS); therefore, it will be. included in the TS which is Appendix A to the operating license.

St. Lucie 2 SSER 3 2-1

3 DESIGN CRITERIA-STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3.5 Missile Protection 3.5.3 Barrier Design Procedures In Supplement 2 to the SER (SSER 2), the staff reviewed and evaluated the FP&L request and justification to strengthen a few missile barrier items at the first refueling. The strengthening was being done because the design was based on a ductility ratio greater th~n the staff criteria of 10. The staff found the justification acceptable.

The committed action by the applicant was inadvertently considered by the staff to be a license condition. The staff corrected this based on the FP&L commitment.

3.8 Design of Category I Structures 3.8.4 Other Category I Structures In the October 1981 Safety Evaluation Report (SER) for St. Lucie*2, it was stated that the applicant's design criteria used for evaluation of masonry walls differed from the staff positions in several areas. As a confirmatory item, the applicant agreed to use the SEB staff positions in a reevaluation of St. Lucie 2 masonry walls prior to fuel loading and plant startup. The staff has reviewed and evaluated the applicant's final response to NRC Question 220.37 regarding masonry walls at St. Lucie 2, dated October 29, 1982 as follows:

The safety-related masonry walls in the St. Lucie 2 plant were reevaluated by the applicant in accordance with the 11 SEB Criteria for Safety-Related Masonry Wall Evaluation." As a result of the reanalysis, it was found that 31 multi-wythe walls required "through bolting" to achieve composite action in order to improve their moment resisting capability. One of this group plus eight addi-tional walls required external reinforcing in the form of structural steel members as well as through bolting.

In its review, the staff considered the use of through bolts or external rein-forcing in the form of structural steel members as "special construction" not covered by the ACI-531-79 or UBC-79 codes. As such, the staff reviewed typical detail calculations for each type of special construction mentioned above. The staff found for both types of special construction that the calculation followed established principles of engineering mechanics and took into account sound engineering practices. As a result, the staff concludes that the analysis and design used in both special construction techniques will enable the affected walls to maintain their structural integrity under loadings anticipated during their service lifetimes.

St. Lucie 2 SSER 3 3-1

The criteria used in the analysis and design of the Category I masonry walls to account for anticipated loadings that may be imposed upon the structures during their service lifetime are in conformance with the staff's criteria for masonry walls found in Appendix A to SRP Section 3.8.4, and with codes, standards and specifications acceptable to. the staff. The staff concludes that in.the event of earthquakes and various postulated accidents the Category I masonry walls will withstand the specified design conditions without impairment of structural integrity. Conformance with these criteria constitutes an acceptable basis for satisfying, in part, the requirements of General Design Criteria 2 and 4.

3.9 Mechanical Systems and Components The staff has reviewed the responses submitted by the applicant to questions regarding the design of concrete expansion anchors to account for base plate fl exi bi l i ty.

These anchors were initially designed based on a factor of safety of 15 but with a plate flexibility procedure which we have found unacceptable. This procedure has been replaced with a design method based on the application of the finite element method through the computer program ANSYS. We have reviewed this design method and have found that it properly includes the flexibility of the base plate in calculating the loads acting on the anchored bolts. The applicant's criteria for expansion anchor and base plant design have therefore been revised to include the fo]lowing criterion:

"The use of a safety factor of 15 for all types of loading precludes the necessity of a prying calculation. Where the use of safety factor of 15 is impractical and the presence of large loads results in a significant prying effect, base plates shall be analyzed using the ANSYS finite element computer program. 11 The applicant has documented this criterion in letter L-82-408 dated September 21, 1982. We find this acceptable, and consider the issue of plate flexibility resolved.

3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core Support Structures 3.9.3.1 Loading Combinations, Design Transients and Stress Limits The Brookhaven National Laboratory (BNL) has completed the analysis of two sample piping systems in the St. Lucie Unit 2 plant. These analyses have pro-vided reasonable assurance that the applicant's modeling and analysis method-ology of piping system is correct. BNL has also verified that these systems meet the applicable ASME Code requirements. For a certain type of reducing outlet branch*connections known as Weldolet tees, the staff concluded that non-conservative stress intensification factors (SIFs) were applied. At the present time, the ASME Code does not specify SIFs for this type of branch connections.

This conclusion on nonconservatism is based on a review of data of recently completed tests on these branch connections. This data is expected to provide St. Lucie 2 SSER 3 3-2

the basis for a Code revision to cover this type of branch connection in the future.

The SIFs used to determine thermal stresses in these Weldole~ tee branch connections can be nonconservative by as much as a factor of two. Since the Code-allowable stresses contain an average factor-of-safety of four to avoid fatigue failure in the first 1000 thermal cycles, the design of St. Lucie 2 ASME Class 2 piping systems is considered to be sufficiently conservative even though these SIFs are underestimated by a factor of two if the plant full temperature cycles is less than 1000.

In addition to fatigue considerations, review of available single load capacity test data of branch connections indicates that sufficient margin exists in the allowable stress limits so that even if these SIFs are underestimated by a factor of ~wo, Weldolet tee branch connections are capable of withstanding, without gross plastic deformation, the applied moments due to the.design and service loads.

Based on these conclusion and the BNL confirmatory results, the applicant was requested to show that the maximum number of equivalent full temperature cycles (as defined by the tode) in any safety-related Class 2 piping system was less than 1000 cycles.

The applicant has evaluated the number of equivalent full temperature cycles for each Class 2 piping system where Weldolet tee branch connections exist, and has determined that in no system does the number of cycles exceed the cri-terion above. The staff has reviewed the worse case cycle evaluation and has found it acceptable and, therefore, considers its confirmatory piping system analysis s~tisfactorily concluded.

3.9.6 Inservice Testing of Pumps and Valves In the St. Lucie Unit 2 Safety Evaluation Report, the staff identified a confirmatory item regarding the periodic leak testing of pressure isolation valves. Specifically, we stated that the applicant was requested to submit a complete list of all pressure isolation valves for inclusion in the plant Technical Specifications along with an explanation of the proposed methods for leak testing and analytical correlations and specific acceptance criteria for test methods other than those utilizing direct volumetric leakage measurements.

The staff position is that all pressure isolation valves, with the exception of motor-operated valves, must meet a 1.0 gpm maximum leak rate criteria at full reactor coolant system pressure. Motor-operated valves must meet a leak rate criteria. of no greater than 5.0 gpm. Additionally, for motor-operated valves, the increase in the leakage rate from the previous test cannot exceed 50% of the difference between 5 gpm and the leak rate measured in the previous test.

The minimum test differential pressure shall not be less than 200 psid, and

• leak rates shall be corrected to 2235 + 20 psig reactor coolant system pressure.

These requirements, which limit conditions for operation should the leak rates

_exceed these limits, along with the following list of pressure isolation valves, will be included in the Technical Specifications.

St. Lucie 2 SSER 3 3-3

LIST OF REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES CHECK VALVE NO. MOTOR-OPERATED VALVE NO.

V 3217 V 3480 V 3227 V 3481 V 3237 V 3651 V 3247 V 3652 V 3258 V 3259 V-3260 V 3261 V 3215 V 3225 V 3235 V 3245 V 3524 V 3525 V 3526 V 3527 All the above valves are within the ASME Class 1 boundary. The staff has discussed these test criteria and the valve list with the applicant and the applicant*has committed to test the listed valves in accordance with these criteria.

The applicant has proposed and submitted a test procedure involving the pressure monitoring of the fluid space between two pressure isolation valves for the following specific check valves in the low pressure safety injection and high pressure safety injection systems: V 3217, V 3227, V 3237, V 3247, V 3525, and V 3527. The applicant has demonstrate~ to the staff his ability to perform these tests with available test connections and instrumentation. The rate of pressure rise of the enclosed fluid will be correlated to leakage and compared.

to the 1.0 gpm leak rate acceptance criteria. If greater than acceptable leakage rates are measured by this method, volumetric leak rate tests will be then performed for verification. The staff finds the general approach to performing this type of testing and the procedures involved acceptable for meeting the staff position on leak testing. Pressure isolation valves other than these will be tested using volumetric leak rate type testing whereby leakage will be detected as it exits through small pipeline sample or drain connections. We also find the general approach to performing this type of testing and the procedures involved acceptable.

• 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment 3.10.1 Seismic and Dynamic Qualification - Introduction In Section 3.10.1 of the supplementary Safety Evaluation Report No. 2, we con-cluded that in order to complete our review, we 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 St. Lucie 2 SSER 3 3-4

post-audit submittals on July 13 and October 29, 1982. Our concerns as identi-fied in SSER No. 2 and the corresponding disposition of them based on the above applicant's submittals are summarized below:

3.10.1.1 -Resolution of Concerns Identified in SSER. No. 2.

3.10.1.1.1 Generic Open Items

a. The loading imposed by piping on all valves and line-mounted instruments should not exceed the acceleration levels CG-values) to which they are qualified: The applicant informed the staff in his October 29, 1982 sub-mittal *that he has verified that the G-levels specified for purchasing of valves and line-mounted instruments are larger than the actual computed G-values from piping stress analysis. This concern is therefore resolved.

b. Boltdown of transformers in switchgear cabinet: The applicant is committed to an inspection of all the current ground transformers in safety-related switchgear cabinets. The inspection will include both visual inspection and torque test of the transformer mounting bolts to certify proper installation per vendor manual, and will be carried out for all 25 of the current transformers located in the switchgear cabinets. This inspection program will be conducted prior to fuel load but subsequent to hot opera-tions testing which is presently under way. The results of this inspection will be retained in the plant files for NRC reivew. The staff found this response acceptable and this concern is considered resolved.

c. Corrosion protection of safety-related equipment: The applicant -informed the staff in his October 29, 1982 submittal that the applicant maintains a program by which all safety-related structures and equipment are inspected on a periodic basis for degradation due to corrosion. These inspections are performed on a routine basis when plant operating modes are changed from mode 4 to mode 3. Any corrosion which is detected during this inspec-tion is corrected using normal maintenance procedures. This inspection program is contained in the site quality control procedures and the inspec-tion interval will never exceed once in 18 months. The staff considers this response acceptable and this concern is resolved. *

d. Provide verification and written justification that unqualified limit switches will not hamper operation of any of the safety-related valves:

The applicant informed the staff that there are no unqualified limit switches in balance of plant (BOP) scope of safety-related valves. In a letter dated November 10, 1982, the appplicant stated that the original classification of some limit switches in the nuclear steam supply system (NSSS) scope to be unqualified was in fact erroneous. Upon recheck, the applicant found that there are no unqualified limit switches in either BOP or NSSS scope. This issue is now considered resolved.

e. Sequential Test Concern: As stated in SSER No. 2, the applicable equip-ment environmental qualification standard for St. Lucie 2 is IEEE Std.

323-1974, and IEEE Std. 344-1975 is an ancillary stan9ard of it. The applicant is required to identify those safety-related equipment for which testing was done in a sequential manner and provide his approach and the corresponding schedule to establish conformance to the requirements of St. Lucie 2 SSER 3 3-5

IEEE Std. 323-1974. This response was provided in the applicant's sub-mittal for Environmental Qualification review (Section 3.11 of this SSER) and was found acceptable by the staff. This concern, therefore, is

• resolved.

3.10.1.1.2 Specific Open Items

a. Recorder No. M226S - The Required Response Spectra (RRS) is needed for the location on the main control board on which the recorder is installed, in order to compare with the test response spectra (TRS) of the recorder for verification of acceptability. The applicant provided worst case RRS curves fo.J. control board and the staff found they are enveloped by the TRS curves used to qualify the recorders, therefore this concern is reso~ved.

b. HPSI Pump and Motor: All missing information identified in SSER No. 2 was resolved by the applicant. The Seismic Qualification Review Team (SQRT) reviewed the new information and found it acceptable. This concern is

. resolved.

c. LPSI Pump and Motor: The missing Sections G, H, .I and J of the motor qualification report was provided by the applicant. The *sQRT reviewed these sections together .with the applicant's submittal of October 29, 1982 on the same subject and found the responses acceptable. This concern is resolved.

d. 1011 Butterfly Valve, Valve FCV-3301: Information on wedge pin-wafer hub stresses was provided by the applicant. They are found to be much lower than the allowable values. Therefore, this concern is now considered resolved.

e. Intake Cooling Water Pump: A meeting was held with the applicant on October 27, 1982 in order for the staff to discuss and to resolve the con-cerns identified in SSER No. 2. The meeting summary (dated November 2, 1982) issued by the NRC documented the responses provided by the applicant in the meeting. The applicant stated that the permissible pressure on the wear ring projected area is based on the permissible pressure in Mark's Handbook as outlined for standard pump design practice. The pressure assumes that the film is maintained on the journal and no bearing wear is

_expected. The applicant further proved that no flange bolting on this pump will have combined stresses (seismic plus preload) exceeding the .

elastic limit. Therefore, the staff concluded that this pump is properly qualified seismically and the concerns are resolved.

f. Pressure Transmitter PT-1107: The concern about spacing between tubing and the transmitter was addressed by a calculation submitted by the appli-cant which shows that the vibration of the tubing is less.than the clear~

ance between the tubing and the transmitter and no impact between them was found possible. The staff considers this response acceptable and the concern is resolved.

g. Signal Characterizer: SSER No. 2 stated that the ID tag was missing on the Foxboro cabinet where this signal characterizer is located. The appli-cant informed the staff in his October 29, 1982 submittal, that the missing St. Lucie 2 SSER 3 3-6

tag has been delivered on site and installed. The concern therefore is resolved.

h. 211 Pneumatic Operated Angle Valve: The* verification of the Wang computer code 2200 A/8 was provided by the applicant in the October 29, 1982 sub-mittal. This concern therefore is resolved.

i. 12" Motor Operated Gate Valve V-3517: The missing identification of the computer code which was used to verify the computer code FEAAS6, was pro-vided by the applicant. This concern therefore is resolved.

j. 811 Gate Valve, Valve I-MV-08-14: The applicant notified the staff in his October 29, 1982 submittal that all missing supports were installed as of August 30, 1982. This concern therefore is resolved.

k. Thermocouple Assembly TE-14-3A: The justification of support design was provided by the applicant in his October 29, 1982 submittal. The SQRT reviewed this response and found the modification to the support acceptable.

This concern is resolved.

l. 4.16 kV Switchgear: The justification that the field-welded mounting is at least as strong*as the tested bolted mounting was provided by the appli-

. cant in his October 29, 1982 submittal. The SQRT reviewed this response.

and found the strength of welded mounting is stronger than bolted mounting both in shear and tear. This concern is resolved .

m. 32" MSIV, I-HCV-08-18: The corrosion concern about the support bracket has been addressed and resolved inc of Generic Open Items above. Con-cerns about unsupported airlines and bypass lines have also been resolved by a submittal which demonstrated that these lines are now properly sup-ported. Furthermore, operability of MSIV was confirmed by a seismic test concurrently conducted with the application of 1000 psi differential pres-sure across a 26" MSIV'that is similar to this 32" MSIV. The SQRT reviewed all these responses and found them acceptable. Therefore, all concerns on this valve are resolved.

n. RPS Cabinet: The concern identified in SSER No: 2 is about the operability of modules in the RPS cabinet. Some of the modules were not tested on the cabinet but were tested separately. The cabinet itself was tested with input more severe than the site input. This leads to cases where the TRSs of the modules tested separately do not always envelop the RRSs at module locations generated from the cabinet test. The applicant used a method to derate the RRSs at module locations generated from the cabinet test, in order to simulate the site input. The initial method chosen by the applicant used frequency dependent derating factors derived from the ratios of the cabinet TRS to the modules' RRSs. The effect of these derating factors was that of a transfer function *for transferring the cabinet RRS to the modules'. locations. However, since a response spectrum is a nonunique transformation and a nonlinear function of excitation frequency, there was no justifiable basis (either theoretical or empirical) for use of these factors. At the suggestion of the SQRT, constant (frequency independent) derating factors, based on the minimum ratio between the cabinet TRS and RRS, were subsequently.used to derate St. Lucie 2 SSER .3 3-7

the modules' RRSs. For linear structures this method is theoretically justifiable since both the response spectrum and the structure's response are linear functions of the amplitude of excitation. To account for possible nonlinearities (which should be small due to the low seismicity of the St. Lucie site) a 10% margin was maintained in the derating factors. By using this derating technique the applicant was able to show that the modules' TRSs enveloped the derated modules' RRSs in the cabinet and modules natural frequency ranges. In addition, review of the Ex-core Safety Channel Assembly, the Bistable Trip Unit, the Auxiliary Trip Unit Assembly, and the Core*Protection Calculators Test Reports (supplied in a March 9, 1983 (L-83-130) submittal to NRC, Docket No. 50-389) revealed that no significant anomalies occurred during the seismic qualification ..

Therefore, the SQRT concluded that the RPS cabinet and all the components thereon are qualified for full power operation.

3.10.1.2 Status of Unresolved Concerns That Were Identified in SSER No. 2.

3.10.1.2.1 Generic Open Items Safety-related equipment not yet qualified seismically: The applicant provided a list of safety-related equipment which are not yet seismically qualified. The qualification schedule and justification for interim opera-tion of this equipment were also submitted.

SQRT review of the aplicant's justifications indicated that tests for all NSSS equipment in this category have been successfully completed as of October 29, 1982. The qualification reports for these equipment are, how-ever, still under review by the applicant. The applicant is required to notify the staff in writing when these qualification reports are accepted and issued by the applicant.

The qualification of some of the BOP equipment are not yet complete. This includes electrical panels and boards, instruments mounted thereon as well as valves and other instruments.

SQRT review of the applicant's justifications on the BOP equipment indi-cated that structural integrity of the electrical panels and boards have been substantiated. However, some of the instruments mounted thereon are tested separately.to a generic seismic response spectra (Fig. 1 of ANSI-C37.98-1978). These generic input spectra have not yet been shown formally by the applicant to envelop the St. Lucie 2 site-specific required response spectra. The comparison of the two spectra by the applicant is still in progress. The applicant has informed the SQRT that preliminary review indicated that the generic spectra envelop the site spectra, there-fore the SQRT concluded that these generic spectra are acceptable for interim period for operation up to 5% power. The 2" and under valves, low differential electronic transmitters, QSPDS instrument inverters and radia-tion monitoring system have been tested but formal documentation is still lacking. The applicant stated that baied on the preliminary test reports on these equipment, no problem of any kind was detected, therefore the SQRT concluded that these equipment are acceptable for interim .operation.

The justification of interim operation of isolation relay boxes and iso-limiters are also acceptable to the SQRT based on the similarity with St. Lucie 2 SSER 3 3-8

other qualified units. The HVAC duct air outlets are scheduled to be qualified before escalation beyond 5% power, and the justification for interim operation of this *equipment based on inherent margin was found acceptable to the SQRT.

• In summary, the SQRT found the justifications for interim operation up to 5% power are acceptable. However, all safety-related equipment should be seismically qualified before exceeding 5% power. At the conclusion of the seismic qualification of all safety-related equipment, the applicant should establish and maintain an auditable record.of their qualification.

3.10.1.2.2 Specific Open Items Batteries and Racks: The first three of the four concerns identified in the SSER No. 2 was addressed by the October 29, 1982 submittal and found by the SQRT to be acceptable. An additional submittal on batteries and racks was forwarded to the SQRT on November 24, 1982. However, the last concern is that the seismic tests were performed on new, not pre-aged, batteries. The testing was done in this manner after the pre-aged bat-teries showed problems withstanding temperatures used to simulate aging which was indicated by cracking of battery jars. .

The subsequent explanation provided in support of the j~r*s integrity is in terms of its properties with respect to normal environment at or below 77°F which reportedly did not show any significant degradation in the material properties .. In view*of the cracked jars at 160°F and other aging factors discussed below, the claim of qualified life of 20 years for the batteries is unsupported.

In the prevailing environment the temperature could go as high as 104°F.

The jar has acid in it. There are no mechanical properties of the jar material (LEXAN plastic) available beyond 77°F. Batteries change physi-cally and chemically as they age. The effect of temperature on the aging process is not well understood. Elevating the electrolyte temperature from the nominal 77°F to 92°F will, according to a renowned manufacturer, cut the useful life in half. Another significant aging factor is the sponginess of battery plates that can lead to the loss of d.c. potential after the aged battery is subjected to vibratory motion from an earthquake.

It is noted that new IEEE 535 qualified batteries are qualified for ten years. Based on these considerations it is estimated that age related degradations of the batteries are not likely to occur before ten years.

Since the unaged battery and rack combination was seismically qualified, and since age related degradation is not likely to occur prior to ten years of operation, the staff concludes that operation with currently installed batteries is justified up to ten years from the date of purchase of the batteries.

3.10.1.3 Summary*

Based on the SQRT site audit and the submittals from the applicant, the staff concludes that an appropriate seismic and dynamic qualification program of equipment has been defined and implemented, except as noted below, and that this provides adequate assurance that such equipment will function properly St. Lucie 2 SSER 3 3-9

during and after the excitation from vibratory forces imposed by the safe shut-down earthquake. The exceptions are the remaining unresolved generic and spe-cific items discussed earlier. The requirements in order to resolve the remain-ing items are delineated below.

3.10.1.3.1 Safety-related equipment not yet qualified seismically: for safety-related equipment not yet seismically qualified, the applicant has provided justification for interim operation. Review of these justifications by the SQRT indicated that tests for all NSSS equipment in this category have been successfully completed as of October 29, 1982. For equipment not yet fully qualified to the SQRT criteria in the BOP scope, enough justifications were provided by the applicant, as described in 3.10.1.2.2 above, and were judged acceptable by the SQRT to warrant interim operation up to 5% power. Operation up to 5% power will not involve significant fission product inventory. However, all safety-related equipment should be seismically qualified prior to exceeding beyond 5% power. At the conclusion of the seismic qualification of all safety-related equipment, the applicant should establish and maintain an auditable record. of their qualification.

3.10.1.3.2 Batteries and Racks: Battery and rack combination was seismically qualified using unaged batteries. Since age related degradation is likely to occur beyond ten years of service, at the end of ten years from the date of purchase of the currently installed batteries qualified batteries per IEEE Standard 535-1979 as a minimum should be used.

3.10.2 Operability Qualification of Pumps and Valves 3.10.2.1 Introduction 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 pro-vide 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, con-ducts an onsite 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 configura-tion 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 qualJfi-cation 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, and 30 of Appendix A to 10 CFR Part 50, as well as Appendix B to 10 CFR Part 50.

St. Lucie 2 SSER 3 3-10

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.

In the previous SSER input a number of open items were identified. These open items have since been resolved and are documented below.

3.10.2.2 Generic Concerns 3.10.2.2.1 Preoperational test program During the audit three out of the eight vaJves reviewed did not have preopera-tional test plans. The applicant committed at that time to include these valves in their preoperational test program. The applicant was requested to perform a review of all safety-related active valves to assure these valves are tested as part of the preoperational test program. The applicant was also requested to include in the preoperational test program, check valves which are required to move to perform a safety function.

Florida Power and Light (FP&L) has committed in their submittal of October 29, 1982 to review the preoperational test procedures to insure that all active safety-related valves, as indicated in the FSAR Tables 3.9-9 and 3.9-10, are stroked as necessary under operating flow conditions so as to demonstrate operability under required*safety-related conditions, where system installation, design and operation allow. Any valves not stroked under flow conditions because of system installation and design operational constraints will be stroked dry.

(An example of a valve which cannot be tested prior to operation in-situ is the containment sump check valve which cannot be tested under flow without flooding the containment sump).

The staff finds this acceptable and notes that the preoperational test procedures will be reviewed prior to core load to ensure testing will be performed on all check valves which are required to operate under accident conditions and are located in safety-related systems.

In a letter date March 18, 1983, the applicant noted that some safety-related valves would be tested after core load but before initial criticality. The applicant explained that the reason for this was due to the requirement to test valves wherever possible under operating flow conditions so as to demonstrate operability under required safety-related conditions.

The staff finds this commitment acceptable. Since the safety-related valves will be tested and functional before any critical operations, the activities of the applicant can be performed without endangering the health and safety of the public.

The NRC will verify the completion of this review and testing.

3.10.2.2.2 Maintaining 11 As-Qualified 11 Life In order to maintain equipment in the as-qualified condition some periodic maintenance is required for pumps and valves. For this reason, the NRC staff St. Lucie 2 SSER 3 3-11

reviewed those areas of the maintenanc~ programs which were related to main-taining equipment in the as-qualified condition for the life of the equipment.

During the site review the FP&L staff presented an overview of the St. Lucie 2 maintenance programs. Subsequent discussions have highlighted the fact that

.there are two programs related to performance of equipment and maintenance.

The first program is the Generation Equipment Management System (GEMS) which is designed to identify equipment with chronic failures or requiring unusually frequent maintenance. This equipment will be highlighted for replacement by more reliable equipment if available.

The second program is the preventative maintenance program. This program includes vendor recommended maintenance, as well as maintenance requirements identified by the FP&L staff through experience in other power plants.

FP&L has committed in their letter of October 29, 1982 to include all safety-related mechanical equipment in the plant in the preventative maintenance program. Inclusion of the safety-related pumps and valves in the two programs outlined above should provide an acceptable method of maintaining this equip-ment in the as-qualified condition.

3.10.2.2.3 Missing File Information During the St. Lucie 2 site review hydrostatic and leakage test information was not available in the site files reviewed for two of the five NSSS components reviewed. FP&L was requested to perform an audit of the site files for a representative sample of pumps and valves to establish the completeness of these files.

• FP&L conducted this audit during the week of 10/11 - 10/15, 1982. The qualifi-cation files were reviewed for the presence of the following documents

- Hydrostatic and leakage test data

- Design specifications Purchase orders

- Seismic reports

- Certificates of compliance

- Traceability and sign-off documentation A total of 12 components (9 valves, 3 pumps) were reviewed for completeness of the files. The results were submitted to the staff on October 29, 1982. In summary, the results were all documents were present in the files with the exception of some seismic reports. The seismic reports were filed in the project files at the NSSS and BOP facilities and were being transmitted to the St. Lucie*2* site on an established schedule and will all be available on site by fuel load. All files reviewed cont~ined hydrostatic and leakage test data.

The staff finds the results of this review satisfactory to resolve this issue.

St. Lucie 2 SSER 3 3-12

3.10.2.2.4 Schedule of Completion of Pum~*and Valve Qualification for Operability '

The pump and valve operability qualification for St. Lucie 2 was not complete for a number of components at the time of the audit. FP&L was requested to provide a schedule for completion of the pump and valve qualification. In their response submitted October 29, 1982 FP&L stated that the qualification of pump and valve operability will be complete by fuel load except for those tests which must be performed subsequent to fuel load which are identified in Chapter 14 of the FSAR. These remaining tests will be performed prior to commercial operation.

In addition, environmental and/or seismic qualification for some components may not be complete prior to fuel load. This equipment will be identified and reviewed in Sections 3.10.1 and 3.11 of the SSER.

3.10.2.3 Specific Concerns 3.10.2.3.1 Jamesbury 10 11 Butterfly Valve, FCV-3301 Shutdown Cooling Control Valve Hydrostatic and leakage test certification for this v.alve was not available on site at the time of the site review. A copy of this information has been sub-mitted to the staff on July 13, 1982.

In addition, this valve is used as a throttling valve and as such will be operated in a partially open position. FP&L was requested to identify experi-ence with flow-induced vibration which might produce a cyclic load on this valve. In the letter on October 29, 1982, FP&L submitted a letter from the valve vendor, Jamesbury Corp., which stated the valve vendor had no flow-induced vibration problems identified for similar valves used in other plants. In addition, the throttling function of this valve is experienced only during plant shutdown cooling operations, a short period over the life of the valve.

The NRC staff finds the responses on these issues acceptable.

3.10.2.3.2 Fisher Control, diaphragm operated globe valve V-2650 Hydrostatic and leakage data was not available for this valve at the time of the site review. A copy of this information has been submitted to the staff on July 13, 1982.

In addition, this valve was not included in the preoperational test program at the time of the audit. The applicant has agreed to preoperational testing of this valve.

The NRC staff will verify the inclusion of this valve in the preoperational test program.

3.10.2.3.3 Fisher Controls, 111 diaphragm operated globe valve, HCV-3648 Injection Header Isolation Valve.

St. Lucie 2 SSER 3 3-13

FP&L was requested to confirm the in-line filter in the air line to the sole-noid valve was included ih the site preventative maintenance program. Filter maintenance was required in order to assure a clean air supply to the solenoid valve to reduce failures. FP&L in their submittal of October 29, 1982 verified inclusion of this filter in the periodic maintenance program.

The NRC staff finds the response on this issue acceptable.

3.10.2.3.4 TRW Mission 24 11 check valve; 21-V-7172 Containment.Sump-Check Valve The licensee has agreed to manually cycle this valve, and the other containment sump check valve, prior to operation.

The NRC staff will verify that this valve has been manually cycled.

3.10.2.3.5 Rockwell, 32 11 x 32 11 x 34 11 Globe Valve, I-HCV-08-18, Main Steam Isolation Valve.

No valve .testing information was provided for this valve during the site review for closure under full flow conditions. FP&L was* requested to provide for this valve documentation which shows by model, prototype or similarity tests this valve will close against full flow load.

In the letter on October 29, 1982, FP&L submitted a Rockwell International test report for a 16 11 Figure 1612 valve and an 811 specially constructed test valve.

Both valves were tested for closure under flow condition.

By letter dated November 3, 1982 Rockwell International described additional tests and analysis to assure MSIV operability. Rockwell International has developed by analysis a valve operability assurance methodology based on .

geometric and dynamic similarity in valves. This valve operability methodology requires numerical values for flow coefficients derived from similarity con-siderations. Numerical values for these flow coefficients were obtained from test data on a 6 inch valve geometrically similar to the 32 inch MSIV. Closure of the 6 inch valve was empirically demonstrated and confirmed by analysis.

Closure of the 32 inch MSIV is predicted for the specific conditions of St.

Lucie 2. As part of the operability assurance, the analysis calculates internal pressure distribution, loads on valve components, and closing time. Based on the submitted material the NRC staff concludes that the MSIV will close under full flow conditions.

• 3.10.2.3.6 Byron Jackson~ Intake Cooling Water Pump, ICW Pump 2A The Seismic Qualification Review Team (SQRT) has questioned the methodology used to determine deflections of this pump in a seismic event. The results of this open item and the effect on operability will be covered in the seismic portion of this SSER (Section 3.10.1).

3.10.2.4 Conclusion Based on the results of the site review performed by May 11-14, 1982 and the subsequent submittals by FP&L to resolve open items identified from the site review, we conclude that an appropriate pump and valve operability qualifica-St. Lucie 2 SSER 3 3-14

tion program has been defined which should provide adequate assurance that safety-related function during normal operation and during and after postulated design-basis accident events. This conclusion is subject to the confirmation by the staff of those areas identified within the report as requiring NRC verification ..

3.11 Environmental Qualification of Safety-Related Equipment 3.11.1 Introduction Equipment which is used to perform a necessary safety function must be demon-strated to be capable of maintaining functional operability under all service conditions postulated to occur during its installed life for the time it is required td operate. This requirement, which is embodied in General Design Criteria 1 and 4 of Appendix A and Sections III, XI, and XVII of Appendix B to 10 CFR 50-, is applicable to equipment located inside as well as outside '

containment. More detailed guidance relating to the methods and procedures for demonstrating this capability has been set forth in NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment," which supplements IEEE Standard 323, and various NRC Regulatory Guides and industry standards.

3.11.2 Background NUREG-0588 was issued in December 1979 to promote a more orderly and systematic implementation of equipment qualification programs by industry and to provide guidance to the NRC staff for its use in ongoing licensing reviews. The posi-tions contained in this report provide guidance on (1) how to establish environ-mental service conditions, (2) how to select methods which are considered appro-priate for qualifying equipment in different areas of the plant, and (3) other areas such as margin, aging, and documentation.

Commission Memorandum and Order CLI-80-21 dated May 23, 1980 states that NUREG-0588 forms the requirements that license applicants must meet in order to satisfy those aspects of GDC 4 of Appendix A to 10 CFR 50 which relate to environmental qualification of safety-related electrical equipment. IE Bulletin 79-018, "Environmental Qualification of Class lE Equipment, 11 issued January 14, 1980, and its supplements dated February 29, September 30, and October 24, 1980 established environmental qualification requirements for operating reactors. This bulletin and its supplements were provided to OL applicant.s for consideration in their review.

The qualification requirements for mechanical equipment are principally con-tained in Appendices A & B of 10 CFR 50. The qualification methods defined in NUREG-0588 can also be applied to mechanical equipment.

In response to the above, the applicant provided equipment qualification infor-

• mation by letters dated November 30, 1981, April 2, 1982, August 30, 1982, October 30, 1982, and December 9, 1982 to* supplement the information contained in Section 3.11 of the FSAR.

.,. r, St. Lucie 2 SSER 3 3-15

3.11.2.1 Purpose The purpose of this SER is to evaluate*the adequacy of the St. Lucie Unit 2 environmental qualification program for safety-related equipment.

3.11.2.2 Scope The scope of this report includes an evaluation of the list of systems and equipment to be qualified, the criteria which they must meet, the environ-ments in which they must function, and an assessment of the qualification documentation for equipment. The principal area of review was the qualifica-tion of safety-related equipment which must function in order to prevent or mitigate the consequences of a loss-of-coolant accident or high energy line break inside or outside of containment, while subjected to the harsh environ-ments associated with these accidents. The qualification of safety-related electrical equipment in a mild environment was also evaluated.

• 3.11.3 Staff Evaluation The staff evaluation of the applicant's response included on onsite examination of equipment, audits of qualification documentation, and a review of the appli-cant's submittals for completeness and acceptability of systems and components, qualification methods, and accident environments. The criteria described in NUREG-0800, Section 3.11, Rev. 2 and NUREG-0588 Category I form the basis for the staff evaluation of the adequacy of the applicant's qualification program.

Revision 1 of NUREG-0588 was utilized to clarify staff positions as required.

The staff performed an audit of the applicant's qualification documentation and installed electrical equipment on July 13-16, 1982. The audit consisted of a review of approximately 20% of the applicant's equipment. Qualification docu-mentation for mechanical equipmeni was also reviewed by the staff.

3.11.3.1 Completeness of Safety-Related Equipment The applicant was directed to (1) establish a list of systems and components that are required to prevent or mitigate a LOCA or an HELB and (2) identify components needed to perform the function of safety-related display instrumen-tation, post-accident sampling and monitoring, and radiation monitoring.

The applicant's systems list for the environmental qualification program was com-pared to Table 3.2-1 of the FSAR. Omissions from the harsh environment program were adequately justified by the applicant. Appendix G lists the systems iden-tified and their Class lE function.

Class lE display instrumentation that provides information to the reactor oper-ators to aid them in the safe handling of the plant was included in the program.

The acceptability of qualification for display instrumentation required by Regulatory Guide 1.97 Rev. 2 will be determined-after issuance of the operating license. Certain equipment required by NUREG-0737 "Clarification of TMI Action Plan Requirements" has been included in the environmental qualification program

• and was reviewed in the same manner as for other safety-related equipment.

St. Lucie 2 SSER 3 3-16

3.11.3.2 Qualification Methods 3.11.3.2.1 Electrical Equipment in a Harsh ~nvironment Detailed procedures for qualifying safety-related electrical equipment in a harsh environment are defined in NUREG-0588. Type*testing of equipment in a sequence consisting of pre-aging (thermal, radiation, and mechanical), seismic and dynamic loading, and exposure to LOCA/HELB conditions (where applicable) is the principal method of qualification.

During the review, several motors were found to have been qualified without type testing in the full sequence specified for NUREG-0588 Category I equip-ment (these are noted with a "QC" deficiency in Appendix B). The applicant has provided justification for this practice based on existing industry motor qualification standards and other information. Qualification of motors by these methods is not unique to St. Lucie 2. The motors are qualified to at least the Category II requirements of NUREG-0588 and are acceptable pending resolution of this issue by the staff.

For several items of equipment in the containment, the applicant utilized thermal lag analysis for qualification to the short term, high temperatures of main steam line breaks. For tests already completed, NUREG-0588 permits analysis to supplement LOCA test data to demonstrate qualification for MSLB's.

The staff reviewed this analysis and new test data (in addition to the original LOCA test data) for a solenoid operated valve and finds the approach utilized to be acceptable.

3.11.3.2.2 Mechanical Equipment in a ~arsh Environment Although there are no detailed requirements for mechanical equipment, General Design Criteria 1, "Quality Standards and Records," and 4, "Environmental and Missile Design Bases;" Appendix 8 to 10 CFR 50, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," Sections III, "Design Con-trol" and XVII, "Quality Assurance Records;" and SRP Section 3.11, Revision 1 contain the following requirements and guidance related to equipment qualifica-tion:

0 Components shall be designed to be compatible with the postulated environmental conditions, including those associated with loss-of-coolant accidents.

0 Measures shall be established for the selection and review for suitability of application of materials, parts, and equipment that are essential to safety-related functions.

0 Design control measures shall be established for verifying the adequacy of design.

0 Equipment qualification records shall be maintained and shall include the results of tests and materials analyses.*

The staff review has concentrated on materials which are sensitive to environ-mental effects, for example, seals, gaskets, lubricants, fluids for hydraulic St. Lucie 2 SSER 3 3-17

systems, and diaphragms. Qualification documentation has been reviewed by the staff and conformance with the above criteria verified.

3.11.3.2.3 Safety-Related Equipment in a Mild Environment The requirements for the environmental qualification of safety-related equipment located in a mild environment as discussed in NUREG-0800, Section 3.11, Rev. 2, are:

The design/purchase specifications for equipment shall contain a description of the functional requirements for its specific environ-mental zone during normal and abnormal environmental conditions. A well-supported maintenance and surveillance program in conjunction with a good preventive maintenance program shall be established to assure that equipment that meets the design/purchase specification is qualified for the designed life.

The maintenance/surveillance program data and records shall be reviewed periodically to ensure that the equipment has not suffered thermal and cyclic degradation triggered by abnormal environmental conditions and normal wear due to its service condition. Engineer-ing judgment shall be used to modify the replacement program and/or replace the equipment as deemed necessary.

The staff review verified conformance with the above criteria. Section 3.11.3.3.5 of this report contains additional details concerning the applicant's commitment to a maintenance/surveillance program.

3.11.3.3 Service Conditions NUREG-0588 defines the methods to be utilized for determining the environmental conditions associated with loss-of-coolant accidents or high energy line breaks, inside or outside containment. The review and evaluation of the adequacy of these environmental conditions are described below. The staff has reviewed the qualification documentation to ensure that the qualification conditions envelop the conditions established by the applicant.

3.11.3.3.l Temperature, Pressure, and Humidity Conditions Inside Containment The applicant provided the LOCA/MSLB profiles *used for equipment qualification.

The peak values resulting from these profiles are as follows:

Maximum Maximum Temperature Pressure, OF psig Humidity, %

LOCA 270 42 100 MSLB 420 44 100 The staff has reviewed these profiles and finds them acceptable for use in equipment qualification; i.e., there is reasonable assurance that the actual pressures and temperatures will not exceed these profiles anywhere within the specified environmental zone (except in the break zone).

St. Lucie 2 SSER 3 3-18

3.11.3.3.2 Temperature, Pressure, and Humidity Conditions Outside Containment The applicant has provided the temperature, pressure, and humidity conditions associated with high energy line breaks outside containment. The criteria used to define the size and location of high energy line breaks are described in FSAR Section 3.6. The following areas outside containment have been addressed:

(1) Main Steam Trestle (2) Auxiliary Building The staff has used a screening criterion of saturation temperature at the calculated pressure to verify that the parameters identified by the applicant are acceptable.

3.11.3.3.3 Submergence The maximum submergence levels have been established by the applicant in the environmental qualification program. The inside containment flood level estab-lished by the applicant is an elevation of +26.0 feet and is based on the TMI Action Plan, NUREG-0737, Item II.F.1. Equipment located below this level has been evaluated for submergence qualification. The effects of flooding on safety-related equipment in the auxiliary building were presented by the appli-cant in Section 3.6 of the FSAR and in the applicant's environmental qualifica-tion program. All safety-related equipment subjected to submergence is or will be qualified for submergence or for the time duration necessary for it to com-plete its safety function. The criteria used for determining line breaks which cause flooding and the flood level elevations have been reviewed~bY the staff

-and are acceptable.

3.11.3.3.4 Chemical Spray Chemical spray is available for containment heat removal following a design basis accident. The specified composition of the spray is 1720-2150 ppm boron and 50-65 ppm hydrazine, with a pH of 4.9-7.0. Equipment inside containment was reviewed for qualification under the above conditions~

3.11.3.3.5 Aging The aging program requirements for St. Lucie Unit 2*electrical equipment are defined in Section 4, Category I of NUREG-0588. The degrading influences of temperature, radiation, vibration, and electrical and mechanical stresses should be considered and included in the aging program. Any justifications for excluding pre-aging of equipment in type testing should be established based on equipment design and application, or on state-of-the-art aging techniques. A qualified life is to be established for each equipment item.

In addition to the above, a maintenance/surveillance program should be imple-mented to identify and prevent significant age-related degradation electrical and mechanical equipment. The applicant has committed to follow the recommenda-tions in Regulatory Guide 1.33, Revision 2, "Quality Assurance Program Require-ments (Operation), 11 which endorses American National Standard ANS-3.2/ANSI St. Lucie 2 SSER 3 3-19

NlS.7-1976, "Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants, 11 as noted'in Section 17 of the staff SER for St. Lucie Unit 2 (NUREG-0843). This standard defines the scope and content of a maintenance/surveillance program for safety-related equipment. Provisions for preventing or detecting age-related degradation in safety-grade equipment are specified and include a) utilizing experience with similar equipment, .

b) revising and updating *the program as experience is gained with the equipment during the life of the plant, c) reviewing and evaluating malfunctioning equip-ment and obtaining adequate replacement components*, and d) establishing sur-veillance tests and inspections based on reliability analyses, frequency and type of service, or age of the items, as appropriate. A commitment to imple-mentation by commercial operation has been made by the applicant and will be verified by the staff. The outline of this program and its implementation date is acceptable for the purposes of the environmental qualification program.

3.11.3.3.6 Radiation (Inside and Outside Containment)

The applicant has provided values for*the radiation levels postulated to exist following a LOCA. The application and methodology employed to.determine these values were presented to the applicant in NUREG-0588 and NUREG-0737, 11 Clarifi~

cation of TMI Action Plan Requirements." The staff review determined that the values to which equipment was qualified enveloped the requirements identified by the applicant.

The values specified for use in equipment qualification in the containment* are integrated doses ranging-from 3.8 x 10 6 to 1.5 x 10 7 rads gamma and 2.8 x 10 7 to 1.6 x 108 rads beta. In the auxiliary building, doses of up to 6.6 x 106 rads gamma were used in areas with recirculating fluid lines. These values are acceptable for use in the qualification of equipment.

3.11.3.4 Outstanding Equipment For items not having complete qualification documentation, the applicant has provided commitments for corrective action and schedules for completion. For items not expected to have full qualification by fuel load, analyses have been performed to ensure that the plant can be operated safely pending completion of environmental qualification. These analyses are acceptable.

3.11.4 Qualification of Equipment The following*subsections present the staff's assessment of equipment based on the applicant's submittal, audits of documentation at the plant site, informa-tion in the NRC Equipment Qualification Data Bank, and previous staff evalua-tions of equipment in other plants.

3.11.4.1 Electrical Equipment in a Harsh Environment The staff has separated the electrical equipment in a harsh environment into three categories: (1) equipment requiring replacement prior to plant startup, (2) equipment requiring additional qualification information or corrective action, and (3) equipment considered acceptable pending implementation of the maintenance and surveillance program. An appendix listing equipment in ~ach of these categories is provided. The applicant identified 44 types of equipment St. Lucie 2 SSER 3 3-20

which were assessed by the staff. Of these, 21 are conditionally qualified, and for the remaining 23 items, qualification is in process.

3.11.4.1.1 Equipment Requiring Replacement Prior to Plant Startup*

Appendix D identifies equipment which the staff review has determined requires replacement prior to plant startup. There_is no equipment in this category for St. Lucie Unit 2.

3.11.4.1.2 Equipment Requiring Additional Information and/or Corrective Action Appendix E identifies equipment in this category. Corrective action or defi-ciencies are noted by a letter relating to the legend identified below.

Legend A - material-aging evaluation; replacement sch~dule; ongoing ~quipment surveillance CS chemical spray EXN - exempted equipment justification inadequate H - humidity I - HELB evaluation outside containment not completed M - margin P - pressure QI - qualification information being developed QM - qualification method J QT - qualification time R - radiation RPS - equipment relocation or replacement schedule provided RTS - retest, schedule provided S - submergence SEN - separate effects qualification justification inadequate T - temperature QC - qualification criteria (Category II in lieu of Category I)

These deficiencies do not necessarily mean that the equipment is unqualified.

However, the deficiencies are cause for concern and have required further case-by-case evaluation.

3.11.4.1.3 Equipment Considered Acceptable or Conditionally Acceptable Based on the staff review, the items identified in Appendix F have been deter-mined to be acceptable, pending implementation of the maintenance/surveillance program .. The applicant should inform the staff of the implementation of the maintenance/surveillance program.

3.11.4.2 Mechanical Equipment in a Harsh Environment The staff selected three items of safety-related mechanical equipment from the master list of equipment to determine if the program described in the environ-mental qualification submittal was satisfactorily implemented. Purchase speci-fications, drawings, materials analyses, and partial test data were provided St. Lucie 2 SSER 3 3-21

by the applicant to demonstrate that essential environmentally sensitive components would withstand the.conditions-associated with LOCAs and HELBs.

The program description and its implementation, based on our audit review, meet the applicable requirements and are acceptable.

3.11.4.3 Equipment in a Mild Environment Two items of equipment were reviewed for conformance with the requirements described in Section 3.11.3.2.3. One item is located in an area which exper-iences a significant increase in radiation dose during a LOCA and is therefore technically in a 11 harsh 11 environment. However, appropriate analysis and test-ing had been performed to demonstrate-qualification. The other item examined was also acceptable. The.program for*,qualification of mild environment equip-ment is acceptable to the staff.

3.11.5 Conclusions The staff has reviewed and evaluated the St. Lucie Unit 2 program for the environmental qualification of safety-related equipment. This review has included the systems selected for qualification, the environmental conditions resulting from design basis accidents, and the methods used for qualification.

The staff concludes that satisfactory completion of the corrective actions identified herein will ensure conformance with the requirements of NUREG-0588 and relevant parts of General Design Criteria 1 and 4 of Appendix A 10 CFR 50, for safety-related equipment.

Subsequent to the review and evaluation described above, the Commission amended its regulations to clarify and strengthen the requirements for environmental qualification of electrical equipment important to safety. To demonstrate compliance with 10 CFR 50.49, which became effective February 22, 1983, the following information is required to be submitted by the applicant before an operating* license is granted:

(1) In accordance with the scope defined in 10 CFR 50.49 provide (a) a list of all nonsafety-related electrical equipment, located in a harsh environment whose failure under postulated environmental condi-tions could prevent satisfactory accomplishment of safety functions by the safety-related equipment. A description of the method used to identify this equipment must also be included. The nonsafety-related equipment identified must be included in the environmental qualifica-tion program.

(b) a statement that all safety-related electrical equipment in a harsh environment, as defined in the scope of 10 CFR 50.49, is included in equipment identified in the submittals listed in 3.11.2.

(c) a list of all post-accident monitoring equipment currently installed, or that will be installed before plant operation, that is specified as Category 1 and 2 in Revision 2 of RG 1.97 and is located in a harsh environment. The equipment identified must be included in the environmental qualification program.

• St. Lucie 2 SSER 3 3-22

(2) Provide information demonstrating qualification of all Unit 2 electrical equipment and added to the program as a result of 10 CFR 50.49 including all safety-related, nonsafety-related, and installed R.G. 1.97 equipment discussed above, or provide justifications for interim operation pending completion of qualification, as required by 10 CFR 50.49. This qualifi-cation information or justification should be submitted to allow sufficient time for staff review and approval before issuance of an operating license.

The applicant must also commit to having all electrical equipment important to safety environmentally qualified by the end of the first refueling outage.

The applicant responded to the above in letters dated March 18, 1983 and March 30, 1983 and stated that no new equipment has been added to the environ-mental qualification program. The staff is currently reviewing the applicant's bases for this conclusion and may require additional information from the applicant prior to St. Lucie Unit 2 exceeding 5% power.

The applicant committed to achieving full :qualification of all equipment within the scope of the 10 CFR 50.49 rule that was published in the Federal Register of January 21, 1983, as interpreted by the applicant, by the end of the first refueling outage. This commitment to achieving full qualification by the-end of first refueling outage meets the rule and is acceptable to the staff. In accordance with the above, the following.license condition is to be met by the applicant.

Prior to exceeding 5% power, the licensee shall complete and submit for NRC staff review and approval the analysis required by 10 CFR 50.49(i).

St. Lucie 2 SSER 3 3-23

4 REACTOR 4.2 Fuel System Design 4.2.3 Design Evaluation 4.2.3. 1 Fuel System Damage Evaluation (a) Design Stress

• The St. Lucie 2 fuel assembly, fuel rod, burnable poison rod (BPR), and control element assembly (CEA) stress analysis results have been submitted (Ref. 1).

These analyses were performed using conventional engineering formula *from standard engineering mechanics textbooks and were performed in accordance with ASME general guidelines for analyzing primary and secondary stresses. The NRC staff has audited some selected stress calculations and concludes that the appr~ach and rationale that were used in each *are reasonable.

For each component, the calculated service stress was found to be less than the allowable stress, which itself was determined from the stress criteria approved previously in the SER (NUREG-0843). The fuel assembly, fuel rod, and BPR calculations are applicable for 3 cycles of operation (32.35 GWd/MTU) and the CEA calculation is applicable for 10 years of .service.

We conclude that the stress calculations for St. Lucie 2 are plausible, logical, and thus acceptable.

(b) Design Strain The recently submitted (Ref. l) strain analysis results for the fuel rod, BPR, and CEA confirmed that these components all will conform to the CE design criterion of less than 1% plastic strain for the duration of their anticipated lifetimes. The analysis methods that were used included those described in the FSAR and the revisions and supplements to CENPD-139, Fuel Evaluation Model" (Ref. 2). No analysis for the fuel assembly structural components was performed inasmuch as the service stresses have been found to be within the unirradiated yield strengths.

We conclude that the strain analyses are acceptable.

(c) Strain Fatigue In the strain fatigue analysis, a maximum cumulative damage factor is calculated (i.e., the sum of the ratios of the number of cycles in a specified effective strain range to the number permitted in that range). The St. Lucie 2 damage factor limit, which was approved in the SER, is conservatively set to 0.8.

St. Lucie 2 SSER 3 4-1

For a traditional fuel lifetime, the cladding damage factor for the St. Lucie 2 fuel rods was found to be substantially less than the 0.8 criterion (the actual CE proprietary value is contained in Reference 1). The cumulative fatigue damage factor for the fuel assembly structure (i.e., guide tubes, upper end fitting springs, etc.) is stated to be insignificant because (a) the antici-pated stresses are within the materials' endurance limits or (b) the predicted number of duty cycles is limited.

We, therefore, conclude that the St. Lucie 2 strain fatigue analysis is acceptab 1e.*

(d) Fretting Wear Fretting wear of the CEA is analyzed in order to ensure conformance to the St. Lucie 2 stress criteria, which were approved in the SER. As discussed in Reference 1, this analysis evaluated the CEA cladding wall thickness by con-sidering such parameters as the predicted cladding ridge height and the fretting wear geometry. This information along with the pressure differential across the CEA cladding wall was then used to calculate a minimum allowable wear depth. The restriction of wear to a minimum depth (a.CE proprietary value) will not only ensure hermiticity but also conformance to the primary and secondary stress criteria.

Confirmation of acceptable levels of CEA fretting wear has been obtained during the second refueling outage of Arkansas Nuclear One, Unit 2 (AN0-2); another CE 16Xl6 NSSS that has improved CEA flow-induced vibrational characteristics over the predeces~or 14X14 design.

On the basis of the above and the FSAR described routine CEA worth testing during refueling outages. we conclude that the issue of CEA fretting wear has been adequately assessed.

(f) Rod Bowing We have recently completed our review (Ref. 3) of the Combustion Engineering generic topical report CENPD-225-P, "Fuel and Poison Rod Bowing, 11 (Ref. 4) and its Supplements (Refs. 5, 6, and 7). Our safety evaluation report concluded that the CENP0-225-P report provided an acceptable methodology for calculating fuel rod bowing penalties. Inasmuch as use of the new method results in smaller thermal-hydraulic penalties as compared to use of the interim-approved method described in the St. Lucie 2 SER, FPL has employed the CENP0-225-P methodology in determining the ONBR penalty for the St. Lucie 2 Technical Speci fi cat i ans.

The burnup-dependent correlation that was used for predicting the gap closure rate for the St. Lucie 2 fuel design was taken directly from the CENP0-225-P report and is hence acceptable. Therefore, the mechanical input to the bowing analysis is acceptable. The development of the thermal-hydraulic penalty and its implementation into St. Lucie 2 Technical Specifications is further de-scribed in Section 4.4 of this SSER.

St. Lucie 2 SSER 3 4-2

(g) Axial Growth With regard to CEA axial growth, the St. Lucie 2 fuel has been designed with a minimum axial clearance that will preclude contact between the bottom of the CEA fingers and the fuel assembly guide tubes. In the design calculation, worst-case dimensional tolerances were assumed and relative thermal growth between fuel assemblies and CEAs was assessed. As the fuel assembly guide tubes .elongate in-service due to stress-free irradiation-induced growth, additional clearance will be achieved. The calculated minimum design clearance (a CE proprietary value contained in Reference 1) for the St. Lucie 2 CEAs has been determined as sufficient for the intended CEA lifetime.

We conclude that the FPL analysis of CEA growth is reasonable and acceptable.

With regard to fuel rod axial growth, the St. Lucie 2 SER discussed that the Combustion Engineering topical report CENPD-198, 11 Zircaloy Growth In-Reactor Dimensional Changes In Zircaloy-4 Fuel Assemblies, 11 (Ref. 8) and its two Supplements (Refs. 9 and 10) were used to predict the differences in axial growth between fuel rods and fuel assembly guide tubes. The CENPD-198 reports, which are approved (Ref. 11) for generic licensing applications involving exposures up to 22.5 GWd/MTU, were developed from fuel performance data taken on CE 14X14 NSSS fuel. As stated in the St. Lucie 2 SER, any unanticipated growth or mechanical interference in the CE 16Xl6 fuel would be evident during routine postirradiation examination (PIE) to be conducted during refueling outages at St. Lucie 2 or from surveillance of lead-burnup precharacterized assemblies in the joint CE/EPRI program being conducted in AN0-2.

Recent measurements (Ref. 12) taken during the second AN0-2 refueling outage have revealed excessive shoulder gap reduction that was partially attributable to pellet cladding mechanical interaction (PCM!) and other unanticipated variables. Subsequently, mechanical modifications to the most-affected assemblies were performed by the licensee to increase shoulder gap clearance for the AN0-2 cycle 3 duration.

As yet the CE Task Force investigating the AN0-2 shoulder gap problem has not completed its review. Thus the variables responsible for the enhanced gap reduction and their relative importance in St. Lucie 2 are unknown.

Consequently, FPL has, as described in a March 24, 1983 letter from R. E.

Uhrig to D. G. Eisenhut, made a fuel design change that provides more clearance for sixteen Batch Band all of Batch C fuel assemblies.

This recent design modification to flow plates, holddown plates, and corner

• posts in the selected assemblies provides about 50% additional shouder gap spacing.

The 50% value is not the result of an analytical determination but rather the maximum value that was physically permissible without entailing an extensive redesign and remanufacturing of the St. Lucie 2 fuel. The modification was accommodated within the original assembly design length and holddown spring spacing envelopes. The modification did, however, necessitate a reduction in the maximum allowable lifting load from 5,000 pounds to 3,000 pounds. Never-theless, no technical specifications changes are necessary inasmuch as the St.

Lucie 2 fuel handling crane trip set-points will be set to preclude loadings of 3,000 pounds.

St. Lucie 2 SSER 3 4-3

During a March 3, 1983 meeting with FPL~ Ebasco, and CE, the NRC staff was informed of several improved design aspects (from a shoulder gap reduction point of view) in St. Lucie 2 as compared to AN0-2. These include lower primary coolant flow, all cold-worked guide tubes, generally higher fuel prepressurization, and reduced holddown spring force. The NRC staff accepts these design differences as unequivocal improvements. We note, though, that these improvements could be insufficient to compensate for the reduced shoulder gap spacing in St. Lucie 2 (i.e., the modified St. Lucie gap is only about three quarters of that for AN0-2).

Because uncertainty remains as to whether shoulder gap reduction as extensive as observed in AN0-2 will occur in St. Lucie 2, the adequacy of the St.

Lucie 2 Batch Band C shoulder*gap clearance cannot be verified for design burnups. Therefore, a license condition is needed to require resolution of the issue prior to the St. Lucie 2 second cycle of operation. Pertinent factors in the "NRC staff review will probably include (but not necessarily be limited to) the St. Lucie 2 fuel modification that has been performed and the differences between the AN0-2/St. Lucie 2 (a) burnup at which PCM! commences, (b) cold work and texture of fuel assembly*guide tubes, (c) as-designed and as-modified shoulder gap clearances, and (d) holddown spring force, and also certainly the results of end-of-cycle-one visual surveillance.

(h) Rod Pressure To demonstrate that the St. Lucie 2 burnable poison rod (BPR) internal pressure will remain below nominal coolant system pressure and hence comply with the gas pressure criterion of Section 4.2 of the Standard Review Plan, a maximum end-of-life pressure was calculated. The calculation employed the percent helium release approved in the SER and accounted.for burnup-dependent parameters (as given in CENPD-269-P (Ref. 13)) that affect the BPR internal void volume.

The maximum BPR pressure (a CE proprietary value given in Reference 1) was found to be less than the nominal coolant pressure of 2250,psi. Consequently, the applicant has satisfied the BPR pressure criterion.

4.2.3.2 Fuel Rod Failure Evaluation (g) Mechanical Fracturing As stated in Amendment 10 to the St. Lucie.2 FSAR, previous analyses (such as for the San Onofre plants) have shown that the limiting cladding stress condi-tions from externally applied forces (i.e., hydraulic loads or core-plate motion) will occur during a seismic and LOCA event. Hence, if the fuel rod mechanical performance during such a limiting event is acceptable, then by deducti~n, fuel rod fracture due to other events would not be expected.

As discussed in Section 4.2.3.3(d) below, the St. Lucie 2 seismic-and-LOCA analysis has been submitted (Ref. 14) and found acceptable. Cladding St. Lucie 2 SSER 3 4-4

stresses were found to be less than the allowable stress. Therefore, the issue of fuel rod mechanical fracture analysis is resolved.

I l 4.2.3.3 Fuel Coolability Evaluation .

(a) Fragmentation of Embrittled Cladding Our evaluation of methods used to show that coolability is maintained included the steady-state fuel performance code,* FATES-2. This code provides fuel pellet temperatures (stored energy) and fuel rod gas inventories for the ECCS evaluation model as prescribed by 10 CFR 50 Appendix K. Although the FATES-2 code was previously approved by the NRC staff, its validity at high burnup has been questioned. The applicant's safety:analyis was therefore accepted only for low burnups (i.e., less than 20 GWd/MTU).

In a letter dated March 10, 1983 (Uhrig to Eisenhut), the applicant stated that future safety analyses will be performed for St. Lucie Unit 2 using the FATES-2 code with an NRC-supplied correction factor (NUREG-0418) or with other approved methods. In the meantime, reanalysis for Cycles 1 through 3 at St.

Lucie 2 was performed with FATES-2 with the NRC-supplied correction, and the results show that applicable limits continue to be met for all anticipated burnup levels. We find this result acceptable and conclude that the issue has been resolved in a satisfactory manner.

(d) Structural Damage From External Forces The final analysis of the St. Lucie 2 seismic and LOCA mechanical loads on -core components has been recently submitted (Ref. 14). This analysis was performed using the revised methods and criteria given in CENPD-178, "Structural Analysis of Fuel Assemblies for Seismic and Loss of Coolant Accident Loading, 11 (Ref. 15) which has been approved (Ref. 16)*for generic reference in licensing applications.

As outlined in the report, peak loads due to a safe shutdown earthquake and a LOCA are combined via the square root of the sum of the squares. For the limit-ing core component, the spacer grids, and the limiting analyses, which are the 4 and 17 fuel assembly row cases, the one-sided and through-grid combined loads have been determined to be less than the allowable critical values. Therefore, we conclude that the seismic and LOCA loading analysis is satisfactory.

4.2.5 Evaluation Findings The staff has performed an indepth review (Ref. 17) of some of the fuel analyses evaluated herein. The analyses were found to be reasonable and thus acceptable.

There is one license condition resulting from our review of _the St. Lucie 2 FSAR Section 4.2, fuel rod axial growth, which is discussed in SSER 3 Section 4.2.3.l(g).

This license conditions will require satisfaction prior to the second cycle of operation.

St. Lucie 2 SSER 3 4-5

4.4 Thermal-Hydraulic Design 4.4.3 Design Abnormalities 4.4.3. 1 Fuel Rod Bowing With the approval of the topical report CENPD-225, "Fuel and Poison Rod Bowing," (Ref. 4) and* its .supplements, as explained in Section 4.2.3. l(f) of this supplement, smaller hydraulic penalties from rod bowing are now predicted as compared to those using the previous interim method. Using CENPD-225 with some added conservatism, the applicant has revised (Ref. 18) the values previously sub~itted in the FSAR. The iew penalties to be applied to DNBR and the integrated radial peaking factor, Fr, are:

DNBR Penalty BURNUP of Bundle DNBR With Grid Spacing Penalty Multiplier toTbe (GWd/MTU) Penalty (%) Penalty(%) Applied to Measured Fr--

0-10.0 0.5 1. 5 1. 013 10.0-20.0 1. 0 2.0 1. 017 20.0-30.0 2.0 3.0 1. 026 30.0-40.0 3.5 4.5 1. 038 40~0-50.0 5.5 6.5 *l. 055 The *penalty is to be applied as a multiplier to the integrated radial peaking factor and, as given, includes the 1% DNBR penalty for grid spacing. This penalty is in addition to those required by CENPD-225 and is because of the longer grid spacing for the St. Lucie Unit 2 fuel assembly as compared to the grid spacing in the original DNB tests. The penalties taken by the licensee are conservative relative to those required by CENPD-225 and are acceptable to the staff.

• The applicant has placed the peaking factor reduction shown above into the Technical Specifications .. The applicant should also insert into the basis of the Technical Specifications any generic or plant specific margin that may be used to offset the reduction in DNBR due to rod bowing and reference the source and staff approval of each generic margin. The staff concludes that the fuel rod bowing penalties have been adequately accommodated.

4.4.4 Loose Parts Monitoring The applicant had committed to provide a description of the training program for plant personnel.that addresses operation of the loose parts monitoring system hardware. This has been provided by Reference 19 and is acceptable to the staff.

4.7 References

1. 11 st. Lucie Unit No. 2 Fuel and CEA Design Summary Evaluation Report," CE Report CEN-222(L)-P, October 1982. Enclosure to R. E. Uhrig (FPL) letter to D. G. Eisenhut (USNRC), October 26, 1982.

• 2. "Fuel Evaluation Model , 11 CE Report CENPD-139, July 1974.

St. Lucie 2 SSER 3 4-6

3. L. S. Rubenstein (USNRC) memorandum for T. M. Novak, 11 SERs for Westinghouse, Combustion Engineering, Babcock &Wilcox, and Exxon Fuel Rod Bowing Topical Reports," October 25, 1982.

4. "Fuel and Poison Rod Bowing, 11 CE Report CENPD-225-P, October 1976.

5. "Fuel and Poison Rod Bowing, 11 CE Report CENPD-225, Supplement 1, February 1977.

6. "Fuel and Poison Rod Bowing, 11 CE Report CENPD-225-P, Supplement 2-P, June 1978.

7. "Fuel and Poison Rod Bowing, 11 CE Report CENPD-225-P, Supplement 3'-P, June 1979. ,-

8. 11 Zircaloy Growth: In-Reactor Dimensional Changes in Zircaloy-4 Fuel Assemblies," CE Report CENPD-198, December 1975.

9. 11 Zircaloy Growth: Application of Zircaloy Irradiation Growth Correlations for the Calculations of Fuel Assembly and Fuel Rod Growth Allowances," CE Report CENPD-198, Supplement 1, December 1977.

10. "Response to Request for Additional Information on CENPD-198-P, Supplement l, 11 CE Report CENPD-198, Supplement 2-P, November .1, 1978.

11 . . R. L. Baer (USNRC) letter to A. E. Scherer (CE), August 21, 1979.

12. Arkansas Power and Li ght/CE/USNRC mee*ti ng handout II Fue 1 Shoulder Gap Modification," October 6, 1982 (CE proprietary).

• 13, "Extended Burnup Operation of Combustion Engineering PWR Fuel, 11 CE Report CENPD-269-P, April 1982.

14. "Final Assessment of St. Lucie-2 Fuel Structural Integrity Under Faulted Conditions," CE Report CEN 187(L)-P, Rev. 1-P. Enclosure to R. E. Uhrig (FPL) letter to D. G. Eisenhut (USNRC), October 26, 1982.

15. Structural Analysis of Fuel Assemblies for Seismic and. Loss of Coolant Accident Loading," CE Report CENPD-178-P, Rev. 1-P, August 1981.

16. L. S. Rubenstein (USNRC) memorandum for R. L. Tedesco, "Safety Evaluation of CE Seismic and LOCA Loads Analysis," June 17, 1982.

17. D. A. Powers (USNRC) memorandum for C. H. Berlinger, "Summary of Meeting with FPL and CE to Discuss Unresolved Issues in St. Lucie 2 SER, 11 November 26, 1982.

18. R. E. Uhrig (FPL) letter to D. G. Eisenhut (USNRC), Number L-82-450, October 21, 1982 ..

19. R. E. Uhrig (FPL) letter to D. G. Eisenhut (USNRC), Number L-82-465, October 27, 1982.

., St. Lucie 2 SSER 3 4-7

l 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.2 Integrity of Reactor Coolant Pressure Boundary 5~2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing This evaluation supplements our conclusions in the SER. Our initial evaluation addressed the following subjects:

a. Compliance with requirements identified in the Standard Review Plan.

b. Definition ~f examination requireme~ts.

c. Evaluation of compliance with 10 CFR 50.55a(g).

Our initial evaluation determined that the Preservice Inspection Program (PSI) was technically acceptable although the examination of the reactor*vessel was still being reviewed. The applicant committed to identify all plant specific areas where ASHE Code Section XI requirements could not be met and provide a supporting technical justification.

• The information pertaining to the reactor vessel was incomplete because a contract for the examination had not been.awarded before our initial review.

The applicant committed to perform the preservice inspection of the reactor vessel based on the provisions of Regulatory Guide 1.150. We considered the examination of the reactor vessel to be a confirmatory issue*because the appli-cant had recently performed an inservice inspection of one of his operating reactor vessels based on this regulatory guide~

In a letter dated November 10, 1982, the applicant submitted the confirmatory information on the reactor vessel examination. The applicant provided a .summary description, with drawings and tables, identifying the limitations of the mechanized examination of the reactor vessel due to physical restraints and inspection instrumentation. Our review has determined that the reactor vessel examination was performed to the provisions of Regulatory Guide 1.150 to the extent practical, thereby resolving this issue.

In a letter dated November 10, 1982, the applicant requested relief from certain PSI requirements and provided a supporting technical justification. The relief requests involve three issues: (1) incomplete coverage of the weld volume subject to examination, (2) the use of fabrication records as an alternative examination, and (3) calibration standards. We have determined that certain American Society of Mechanical Engineers (ASME) Code Section XI examination requirements defined in 10 CFR 50, Section 50.55a(g)(3) are impractical.

We have evaluated the ASME Code required examinations and, pursuant to. 10 CFR SO, Section 50.55a(a)(2), have allowed relief from the requirements that have been determined to be impractical, and that if implemented would result in hardships or unusual difficulties without a compensating increase in the level of quality St. Lucie 2 SSER 3 5-1

\

and safety. Based on the granting of relief.from these preservice examination requirements, we conclude that the preservice inspection program for St. Lucie Unit No. 2 is in compliance with 10 CFR Part 50, Section 50.55a(g)(3). Our detailed evaluation supporting this conclusion is provided in Appendix C to this report.

The question of evaluation standards for ultrasonic indications using ASME Code acceptable procedures on roll-bond clad reactor coolant system piping was discovered by Region personnel and reported in a letter dated July 13, 1982.

The Applicant replied to this matter in a letter dated August 20, 1982. For examination of the clad pipe in the reactor coolant system, the applicant elected to use Article 4 of Section V of the ASME Code in lieu of Appendix III of Section XI of the ASME Code. In our initial SER, we concluded this option was acceptable because use of Article 4 will provide results equivalent or superior to results from the use of Appendix III.

The applicant had evaluated indications near the ID surface by comparison with a 2% (not'including clad thickness) of thickness deep ID notch. It was observed that the ID notch in the roll-bond clad gave a 14 dB higher signal than the Code side-drilled hole calibration. When two indications near the ID for one weld were evaluated*by Region II personnel and compared with the side-drilled hole calibration, questionable ultrasonic indications were found. The applicant then performed examinations and confirmed the existence of two flaw indications. The applicant described the indications as being from: (1) a string of fine porosity and (2) a "very fine" area of interbead lack of fusion.

Both flaws were described as not extending over 0.1 inch through the wall thickness. Since the applicant has committed to evaluation using side-drilled hole sensitivity, this plant-specific issue is resolved for the preservice

• inspection. We will evaluate the applicant's use of appropriate ultrasonic sensitivities above the requirements of 10 CFR .50.55a(b) during our review of the Inservice Inspection Program.

5.4 Component and Subsystem Design 5.4.3 Shutdown Cooling (Residual Heat Removal).System In Section 5.4.3 of our Safety Evaluation Report of October 1981, we stated that the staff required that St. Lucie Unit 2 demonstrate its ability to cool d~wn using natural circulation in the primary system, including the adequacy of boron mixing during this* mode. The applicant referenced the natural circula-tion and boron mixing tests to be conducted during startup at San Onofre Units 2 and 3 as being applicable to St. Lucie 2. The staff found this acceptable pending a favorable evaluation of the San Onofre test results. The staff however, required that the applicant submit a report following the San Onofre tests, documenting the acceptability and applicability of the San Onofre tests. for St. Lucie. At that time we required that this be done prior to startup testing.

If acceptable tests are not performed at San Onofre, St. Lucie would have to perform boron mixing and natural circulation tests during their power escalation program. FP&L agreed with this requirement.

• In a letter dated October 8, 1982, the applicant indicated that the boron mixing and natural circulation tests were expected to be performed at San Onofre Units 2 and 3 in the first quarter of 1983. This schedule did not St. Lucie 2 SSER 3 5-2

coincide with the present St. Lucie Unit 2 core load schedule. The applicant proposed submitting the report justifying adequate boron mixing during natural circulation cooldown prior to exceeding fifty percent of rated thermal power.

The staff has reviewed the applicant's proposed schedule delay in submitting the above stated report and concludes that it is acceptable. The staff conclu-sion,il. based on the following:

1. St. Lucie Unit 2 has committed to perform natural circulation tests at low power per requirements of item I.G.1 of.NUREG-0737.

2. St. Lucie 2 could perform its own boron mixing and natural circulation cooldown tests during high power testing (50%) if the staff is not satisfied with the San Onofre Unit 2 test results.

In Section 5.4.3 of our Safety Evaluation Report of October 1981, we stated that the applicant was asked to modify St. Lucie 2 emergency operating proce-dures, so that cooldown under natural circulation conditions would not result in upper head voiding. We stated the applicant committed to make these changes.

The staff required that these procedures be modified prior to fuel loading. In addition, since it is expected that a slower cooldown rate will be required to prevent voiding, the staff required that the applicant demonstrate that suffi-cient emergency feedwater is available taking into consideration this newly revised cooldown rate. The demonstration of sufficient feedwater must consider holding the plant at hot shutdown for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and then cooling dowri to the SDCS initiation conditions at a rate which will not induce voiding. This con-firmatory information was to be provided prior to fuel loading.

In Amendment 11 to the FSAR, the applicant has stated that an analytical evaluation of natural circulation cooldown to shutdown cooling system entry conditions without formation of voids was performed. The reactor coolant system (RCS) pressure must be reduced to 275 psia for shutdown cooling initia-tion. Consequently, to prevent the formation of voids, the upper head fluid must .be cooled to a value less than the corresponding saturation temperature of 409.5°F. The results of the analyses indicated that the amount of water re-quired to bring St. Lucie Unit 2 through four hours of hot standby followed by a natural circulation cooldown to the shutdown cooling initiation point using conservative assumptions is 330,900 gallons. The current St. Lucie 2 technical specifications (TS) require a minimum condensate storage of 307,000 gallons reserved for the auxiliary feedwater. The applicant states that the required condensate of 330,900 gallons for cooldown without voiding will be provided by revising St. Lucie 2 operating procedures to establish makeup to the condensate storage tank and to maintain the volume of the tank continuously above the TS limit. The makeup water can be supplied from the two 500,000 gallon city water storage tanks. Pumping capabilities can be provided by the fire pumps wh1ch are loaded onto the diesel generators. We have reviewed the above St. Lucie design features and concluded that they are acceptable provided that the above stated condensate makeup procedures are made available to the operators prior to fuel loading and verified by NRC staff.

The applicant, in Amendment 11 to FSAR, stated that the above analysis was performed for the St. Lucie Unit 1 plant. In response to the staff concern regarding the applicability of these analyses to the St. Lucie Unit 2 design, the applicant, by letter dated November 5, 1982, provide justification as fol-lows: 1) the St. Lucie 1 is essentially the same design as St. Lucie 2. The St. Lucie 2 SSER 3 5-3

fluid volumes and physical arrangement of Unit 2 are virtually identical to the St. Lucie Unit 1 1 and 2) the differences in fuel geometry and the design of auxiliary equipment between the two Units *do not result in any significant dif-ferences in the natural circulation flow conditions. We have reviewed the above applicant's justification and conclude that it is acceptable to refer to the St. Lucie Unit 1 analysis in the evaluation of St. Lucie Unit 2 plant cooldown.

St. Lucie 2 SSER 3 5-4

6 ENGINEERED SAFETY FEATURES 6.2 Containment Systems

.6.2.4 Containment Isolation System The Safety Evaluation Report stated that leakage integrity tests for the con-tainment mini-purge system 8-inch isolation valves will be required and that the testing frequency will be specified in the plant's Technical Specifica-tions (TS). Surveillance Requirement 4.6.1.7.4 of the TS specifies a testing frequency of *92 days. By letter dated March 24, 1983, Florida Power and Light Company (FP&L) informed the staff that because of certain design constraints, the valves cannot be tested during power operation. FP&L has committed to make the necessary design change during the first refueling outage to permit testing during power operation every 92 days. We will require that the license be con-ditioned to include the necessary design change to permit testing. For the interim, FP&L has proposed the following alternative wording of Surveillance Requirement 4.6.1.7.4:

"Each 8-inch containment purge supply and exhaust isolation valve with resilient material seals shall be demonstrated OPERABLE by verifying that the measured leakage rate is less than or equal tq 0.05 La when pressurized to Pa, prior to entry to MODE 4 from COLD SHUTDOWN, if not tested within the previous 31 days. 11 The staff finds this interim surveillance requirement acceptable because the valve seat material is new and because a return to cold shutdown typically occurs several times during a fuel cycle, which will allow ample opportunity for the identification of potential valve seat deterioration. Therefore, the staff concludes that the proposed interim TS for testing the 8-inch purge valves is acceptable.

An inspection of the as-built configuration of the 8-inch continuous contain-ment purge (mini-purge) system has revealed the need for modifications in order to assure the system will function as required in the event of a LOCA. They are:

1. modification to the supply line discharge entering the containment to an elevation which precludes it from being submerged following onset of a LOCA; and . .

2. modification to the exhaust- line to remove a previously unidentified dam-per between the debris screen and the inboard containment isolation valve.

With respect to Item 1, it is necessary for the mini-purge system to remain operable following a LOCA, since 10 CFR Part 50.44 required that a system for controlled purging be provided. The mini-pruge system satisfies this requirement. The staff would find acceptable a modification to the inlet line that precludes its submergence.

St. Lucie SSER 3 6-1

With respect to Item 2, the capability of the damper to survive the dynamic loading conditions associated with a LOCA, and thereby preserve the containment isolation function, has not been evaluated. It is noted that system's

• functional tests have demonstrated that the presence of the damper is unnecessary. Consequently, its removal or the reorientation of the deb~is screen are acceptable alternative to the staff.

By letter dated April 6, 1983, FP&L acknowledged the validity of the two staff concerns regarding the mini-purge system, in the event of a LOCA, and has proceeded to investigate the measures which must be taken to resolve these concerns. FP&L has committed to implement corrective measures that are satisfactory to the staff prior to exceeding five percent power. We find this commitment acceptable.

Since there will not have been any significant buildup of fission product inven-tory nor will there be any significant decay heat rate prior to operations above'five percent of full power, there will not be any significant hazards*

associated with the planned low power operations while the above cited com-mitments are being met. Moreover, the purge system function will not be required if a LOCA were to occur during the planned low power operations.

We recommend resolving this matter by use of a license condition which would prohibit operations above five percent of full power prior to the licensee's installation of the corrective measures.

6.3 Emergency Core Cooling System 6.3.2 Evaluation In Supplement 2 to the SER, the st~ff reviewed and evaluated the FP&L request and justification to have installed and completely operational within twelve months from core load low flow alarms on safety injection pumps. The staff found the justification acceptable.

The committed action by FP&L was inadvertently considered by the staff to be a license condition. The staff corrected this based on the FP&L commitment.

6.3.3. Testing In Section 6.3.3 of our Safety Evaluation Reports of October 1981, we stated that:

"The staff will require experimental verification that the St. Lucie 2 plant can operate in recirculation without cavitation or air entrain-ment problems. The applicant has committed to scale model tests of the SIS sump for vortex formation. We require the test model to include the entire containment emergency sump compartment with the drain tank in the sump, the sump-screen, the flow path entering the sump compartment and the proposed screen partition in between the two pump suctions. The amount of air entrainment was to be measured during tests. 11 The applicant has submitted a report of the model testing of the SIS sump by a letter dated October 6, 1982. The applicant has performed tests of containment St. Lucie SSER 3 6-2

emergency sump hydraulic behavior to study intake head losses and vortex control using a full scale simulation. The test model includes the entire containment emergency sump compartment with drain tank in the sump, the sump screen, the flow path entering the sump compartment and the screen partition in between the two pump suctions, simulating the emergency containment sump features used at St. Lucie 2. During the .tests, heated water was circulated through the sump system at flow rates greater than the maximum value postulated for the worst recirculation case, and at water depth equal to the minimum postulated water level after a LOCA.

In the test, the model sump screen was partially blocked with various geometry blockages to simulate the effects of an accumulation of debris. The tests demonstrated that the St. Lucie 2 sump arrangement prevents vortex carrying air or debris into the pump suctions during post-LOCA recirculation. Only vortex types 1 and 2 (incoherent surface swirl and surface dimple) were observed during the tests and they are not true vortices since they are limited to the surface motion only.

The staff has reviewed the test report, arid concludes that for up to*SO percent blockage of the sump screen, the sump performance is not degraded. Significant (i.e., more than 50%) blockage of the sump screen is precluded by insulation design (see Section 6.3.2 of the SER). Since the measured sump inlet losses are smaller than the assumed value for analyses and flow blockage exceeding 50%

is precluded by insulation design, and the pump runout flow was conservatively used for the calculation of NPSH requirements, we conclude that the St .. Lucie 2 emergency containment sump design is acceptable .

.6. 4 _Control Room Habitability In order to improve the effectiveness of the containment spray system, the applicant proposed that the emergency procedures be modified to include an operator action within one hour following the initiation of that system. This action*c:onsists of one operator, wearing self-contained breathing apparatus, traveling by interior stairway from the control room to the electrical equip-ment room to throw one switch. The staff has evaluated the dose increment of this action to assure that the General Design Criterion 19 dose limitation for control room operators is not exceeded for the single operator due to this increment.

To conservatively estimate the maximum dose received, the staff assumed that all leakage from the containment was uniformly mixed in the 15,500 cubic meter free volume of the auxiliary building, including all locations traveled by the operator outside the control room. The applicant, by timing operators, esti-mated approximately 60 seconds were required to perform the task. The staff allowed 2.5 minutes, and used the peak predicted contamination within the buildirig. The contamination was computed to be 25,500 curies of iodine and noble gas fission products, *principally Kr-88. The resulting dose was computed to be 900 millirem whole body gamma dose.

• We conclude that the maximum dose to any control room operator of the course*

of a loss-of-coolant accident is within the limits of General D~sign Criterion 19.

St. Lucie SSER 3 6-3

6.6 Inservice Inspection of Class 2 and 3 Components This evaluation supplements our conclusions in the SER. Our initial evaluation addressed the following subjects:

a. Compliance with requirements identified in the Standard Review Plan.

b. Definition of examination requirements.

c. Evaluation of compliance with 10 CFR 50.55a(g).

Our initial evaluation determined that the Preservice Inspection Program (PSI) was technically acceptable. The applicant committed to identify all plant-specific areas where ASME Code Section XI.requirements could not be met and provide a supporting technical justification.

In a letter dated November 10, 1982, the applicant requested relief from cer-tain PSI requirements and provided a supporting technical justification. The relief requests involve incomplete coverage of the weld volume subject to examination. We have determined that certain American Society of Mechanical Engineers Code Section XI examination requirements defined in 10 CFR 50, Sec-tion 50.55a(g)(3) are impractical. We have evaluated the ASME Code required examinations and, pursuant to 10 CFR 50, Section 50.55a(a)(2), have allowed relief from the requirements that have been determined to be impractical, and that if implemented would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety. Based on the granting of relief from these preservice examination requirements, we conclude that the preservice inspection program for St. Lucie Unit No. 2 is in compliance with 10 CFR 50, Section 50.55a(g)(3). Our detailed evaluation supporting this con-clusion is provided in Appendix C to this report.

St. Lucie SSER 3 6-4

7 INSTRUMENTATION AND CONTROLS 7.1 Introduction 7.1.5 Site Visit The site visit, which was performed in accordance with Section 7.1.5 of the St. Lucie 2 Safety Evaluation Report (SER), was sufficient to confirm that the design has been properly implemented to meet the applicable design criteria.

Based on our site visit trip report (refer to Appendix H), the NRC staff con-siders the site visit issue to be closed.

7.2 Reactor Protection System 7.2.5 Logic Matrix and Logic Matrix Power Supplies St. Lucie 2 SSER No. 1 (December, 1981) requires the applicant to provide addi-tional information pertaining to testing of the reactor protection system matrix power supplies. The applicant was requested to confirm:

A. That testing has been completed in accordance with the test program which has been reviewed and approved by the staff; B. That the staff approved test program acceptance criteria have been met; and C. That the required ultra isolation transformers have been installed.

Subsequently, the applicant provided formal documentation in letters (R. Uhrig to D. Eisenhut) dated October 29, 1982 and December 22, 1982, which confirms items A and B. The letters also state that the ultra isolation transformers (Item C.) will be installed prior to core load. Based on this additional information, the staff ,concludes that sufficient confirmatory documentation has been provided and thus, this issue is considered resolved.

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 1 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 letters (R. Uhrig to D. Eisenhut) dated May 4, 1982 and October 8, 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.

St. Lucie 2 SSER 3 7-1

The electrical 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 by initial criticality. Also, this system will be required by the Technical Specification to be operable prior to initial criticality. Since this system will be completely installed and functional before critical operations, the activities of the applicant can be performed without endangering the health and safety of the public.

Based on the above requirement and commitment by the applicant, we conclude that the automatic initiation portion of the AFWS need not be completely installed and fully operational prior to initial criticality. The NRC staff will verify complete installation and full operability of the auxiliary feed-water automatic initiation function prior to initial criticality.

7.3.6 Containment Isolation In the St. Lucie 2 SER dated October 1981 and SSER 2 dated September 1982, the ICSB expressed a concern about insufficient diversity for the containment*isola-tion 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 initiated on a safety injection actuation signal (SIAS) as well as on high con-tainment pressure or high containment radiation.

• The St. Lucie 2 SER dated October 1981 requires the applicant to confirm that the CIAS modification has been completed. The applicant has revised the FSAR to reflect the new design and has submitted a letter (R. Uhrig to 0. Eisenhut) dated August 19, 1982, which states that the required design change has been completed and is fully implemented in the field. We find the applicant's confirmatory information acceptable*and consider this issue resolved.

St. Lucie 2 SSER 3 7-2

8 ELECTRIC POWER SYSTEMS 8.1 General We stated in the safety evaluation report that the staff would conduct a review of electrical drawings and would visit the site to view the installation and arrangement of electrical equipment and cables for the purpose of verifying proper implementation of the design as described in the FSAR. In addition, we identified certain items in the SER for design verification during our site visit. A site visit was conducted by the staff on August 30 through September 2, 1982 during which certain concerns regarding conformance to Regulatory Guide 1.75 were identified. Our discussion and resolution of these concerns are addressed below. Items for design verification identified in the SER, are discussed in the appropriate Sections of the SER.

• 1. During our site visit, we were informed by the applicant that barriers or cable tray covers will be installed (where separation is marginal) after all the cables are pulled. We expressed concern how this can be verified.

We required the applicant to specifically identify on a marked set of draw-ings all areas where barriers or cable tray covers will be installed so that I&E can verify these installations on completion. The drawings shall include all pertinent data, i.e., material, size, width, thickness, loca-tion, etc., for identification of each barrier installed.

By letter of.October 29, 1982, the applicant committed to revise raceway layout drawings to indicate where a barrier is required and the type of barrier needed to achieve adequate separation. These drawings will be completed by December 21, 1982 and the implementation of the designed bar-riers will be from January 1983 through June 30, 1983. This satisfies our concern and we find this item resolved. Verification of the implementa-tion of these barriers will be done by the NRC staff.

2. The implementation of the identification and color coding schemes for safety-related circuits and equipment were observed. We found only one place where a small portion of a cable tray (for the selected systems observed) was not identified. By letter of October 29, 1982, the appli-cant committed to properly identify that portion of the cable tray. In addition, the applicant would also check all other circuits to assure this condition does not exist elsewhere in the plant. This will be achieved by an existing QC program which will assure that proper color coding of the raceways is properly implemente~. The discrepancies (if any) will be identified and corrected upon completion of site inspection. This satis-fies our concern and we consider this item resolved.

3. During our drawing audit, we found that the applicant has the capability ta test fast-dead bus transfer of onsite distribution system buses from unit auxiliary transformer to the startup transformers. However, the capa-bility to test thjs circuitry during operation did not appear to exist.

St. Lucie 2 SSER 3 8-1

The applicant was requested to.modify the design to include this design feature.

I,

• By letter of October 29, 1982, the applicant demonstrated that the capa*

bility to test fast-dead bus transfer of onsite distribution system buses from the unit auxiliary transformer to the startup transformers, during plant operation, does exist in the St. Lucie Unit #2 design. This is consistent with the requirements of SRP Section 8.2 and is therefore acceptable.

4. Our review of the diesel generator control drawings revealed that RG 1.108 position 1 lbS 1 regarding surveillance system that indicates which of the diesel generator protective trips is activated first in order .to facil-itate trouble diagnosis, is not implemented in the St. Lucie Unit No. 2 design. We requested the applicant to modify the design to include this design feature.

By letter of October 29, 1982, the applicant provided justification for not having this design feature in St. Lucie Unit 2 design. We have re-viewed this information and conclude that the surveillance system which indicates which of the diesel generator protective trips is activated first in order to facilitate trouble diagnosis is useful only when the diesel generator is under test. This is because during accident condi-tions all protective trips are bypassed with the exception of generator differential and engine overspeed. We believe that this design feature has no safety significance, therefore, the applicant's justification for not implementing this design feature is acceptable.

8.3 Onsite Emergency Power System 8.3.1 Alternating Current Power System We stated in the SER that the load group AB buses can be manually connected to either load A or load group Bin the St. Lucie Unit 2 design. Further, the interconnections to either load group A or load group Bis through two tie breakers connected in series with interlocks between the load group A and load group B incoming breakers which insures that all AB loads are connected to the same division at all times. However, for added assurance that the load group A and B incoming breakers do not close on load group buses AB simultaneously, we required the plant's Technical Specifications include the requirement that these tie breakers be locked open during plant operation.

By letter of October 12, 1982, the applicant responded that the buses serving load group AB can only be manually connected with either load group A or B but never simultaneously. This is accomplished by use of 11 captive key type switches" in the breaker control switches. The keys, which must be inserted to close the breakers, are "captured" and cannot be removed until the breaker switch is placed in the open position. Thus, whenever load group*A(B) is connected to load group AB, the breaker control switches are in the closed position, the keys to operate the switches are "captured" and the control switches for the breakers between load group B(A) and load group AB cannot be operated. Based on this, the applicant argued that no requirement for providing a Technical Specification that these breakers be locked open is necessary. We have reviewed St. Lucie 2 SSER 3 8-2

this information and conclude that inclusion of captive key type switches coupled with annunciation in the control room, which alarms whenever AB buses are not aligned to the same division, in the St. Lucie Unit 2 design provide adequate assurance that independence of load group A and B will not be compro-mised, and we find this to be acceptable.

8.3.1.l' Vital Instrumentation and Contra~ Power Supply In Section 1.9 of SSER 2, the potential replacement of existing sequencing relays with electronic timing relays was listed as a license condition. This has been determined not to be a license condition for the reason discussed below.

In Section 8.3.1.1 of the SER, the staff discussed a concern with the potential setpoint drift of the existing pneumatic diesel generator sequencing relays and resolved the matter by increasing the Technical Specification surveillance rate of these relays. Also in the SER the staff noted that the applicant was also concerned about the setpoint drift and considered replacing the pneumatic relays with electronic timing relays if test demonstrate their reliability. This latter action by the applicant was inadvertently considered a license condition when in fact the staff had found an acceptable solution by having the applicant increase the surveillance rate. Therefore, this item is removed as a license condition.

• 8.3.2 Direct Current Power System We stated in the SER that in addition to the two redundant and independent direct current power systems, a third 125 volt direct current bus (SAB) is provided to supply control power to a third group of safety loads. This third bus SAB can be powered manually from either of the redundant load group A or load group B. The tie breakers to SAB are interlocked to prevent this bus from being simultaneously connected to both redundant de distribution systems. How-ever for added assurance that the load group A and B incoming breakers do not close on load group buses AB simultaneously, we required plant Technical Speci-fications include the requirement that these tie breakers be locked open during plant operation.

By letter of October. 12, 1982, the applicant responded that the buses serving load group SAB can only be manually connected with either load group A or B but never simultaneously. This is accomplished by use of 11 captive.key type switches 11 in the breaker control switches. The keys, which must be inserted to close the breakers, are 11 captured 11 and cannot be removed until the breaker switch is placed in the open position. Thus, whenever load group A(B) is connected to load group AB, the breaker control switches are in the closed position, the key to operate the switches are 11 captured, 11 and the control switches for the breakers between load group B(A) and load group SAB cannot be operated. Based on this, the applicant justified that no TS requirement.that these breakers be locked

• open is necessary. We have reviewed this information and conclude that in-clusion of captive key type switches coupled with annunciation in the control room, which alarms whenever SAB buses are not aligned to the same division, provide adequate assurance that independence of load group A and B will not be compromised. We find this to be acceptable.

St. Lucie 2 SSER 3 8-3

We also stated in the SER that the following indications and alarms of the Class lE de power system status shall :be provided in the control room for St. Lucie Unit 2 design.

• (a) Battery current (ammeter-charge/discharge)

• (b) B~ttery charger output current (ammeter)

(c) DC bus voltage (voltmeter) .

(d) Battery charger output voltage (voltmeter)

(e) Battery high discharge rate alarm (f) DC bus undervoltage and overvoltage alarm

. (g) DC bus ground alarm (for ungrounded system)

(h) Battery breaker(s) or fuse(s) open alarm (i) Battery charger output breaker(s) or fuse(s) open alarm (j) Battery charger trouble alarm (one alarm for a number of abnormal conditions which are usually indicated locally)

In a letter dated March 17, 1982, the applicant clarified that items band d are indicated locally on the individual charger and will not be provided in the control room because there is not enough space on RTGB201 board to accommodate these meters. In addition, item (i) will not be provided separately because it is included in item (j) above. Based on our review of the information provided by the applicant, we conclude that the above items n~ed not be provided in the control room because the battery charger trouble alarm combined with battery high discharge rate alarm provide adequate assurance that the operator would be made aware of malfunction of either battery charger. Therefore, we find this design t~ be acceptable.

In Amendment 11 to the FSAR, the applicant changed the rating of each of the 125 volt safety-related batteries from 1800 ampere hours to 2160 ampere hours.

In addition, each 125 volt de safety-related bus is supplied from two 125 volt de battery chargers operating in parallel instead of one battery charger. The battery chargers are automatically loaded on to the respective diesel generator bus less than a minute after a loss of offsite power. Based on the information provided by the applicant, we conclude that added battery capacity and an extra battery charger for each 125V de safety-related system enhances the capability of the de system for St. Lucie Unit No. 2 and we find this to be acceptable.

8.4 Other Electrical Features and Requirements for Safety 8.4.1 Physical Identification and Independence of Redundant Safety-Related Electrical Systems Our observation of the cable spreading area revealed that there are high energy electrical equipment (transformers) located in the St. Lucie Unit #2 cable spreading area. Moreover, this high energy electrical equipment is not separated by walls or barriers and thus failure of such equipment could have an adverse effect on redundant Class lE cables. We informed the applicant that this was inconsistent with the recommendations of Regu-latory Guide 1.75. We required the applicant to either separate the trans-formers by a wall or suitable barrier or provide justification that fail-ure of these transformers will not jeopardize the independence of the Class lE cables.

St. Lucie 2 SSER 3 8-4

By letter of October 29, 1982, the applicant committe*d to install a suit-able barrier around the transformers prior to startup following first re-fueling. Based on the information provided by the applicant, we conclude that the applicant's commitment is acceptable provided that prior to instal-lation the applicant submits* for NRC review and approval the barrier design to be used and justification for its acceptability. Therefore, the staff will re-quire a license condition for the submittal and installation described above.

• We consider plant operation without the installation of these barriers for this*

time period to be acceptable because (1) the transformers are built in accor-dance with ANSI Standard C57.12.00-1973, (2) the transformers are provided with pressure relief devices which serve to dissipate the build-up of internal pres-sure, (3) the equipment vendor has indicated that they have had no reported tank rupture failures since they have manufactured.this type of liquid (non-flammable) filled transformers, and (4) transformers of similar design have been in operation on St. Lucie Unit 1 for six years with no tank rupture occur-rences. The NRC staff ,will verify the installation of this design modification.

I

• 8.4.2 Nonsafety Loads,on Emergency Power Sources In the SER we noted that the design change to disconnect 4 kilovolt loads on detection of a safety injection signal and to provide two isolation devices in series for those nonsafety loads that are not disconnected py a.safety injec-tion signal or loss of offsite power will require procurement of a considerable amount of new long lead time hardware. Therefore, we agreed to extend comple-tion of these modifications to prior to startup following the first refueling outage. However, we require that the license be conditioned to include these modifications.

In the SER we did not make clear the justification to allow the plant to operate until the modifications have been completed. The justification is given below.

All safety buses in the plant are redundant, failure of one bus does not render the plant unsafe. The safety buses are presently protected by at least one isolation device and this provides a high level of reliability because of the pedigree of these installed devices. Failure of a piece of electrical equipment in a manner that could jeopardize a bus is not a likely occurrence. The safety buses themselves are protected by isolation devices from impacting other buses; fault identification and repair could allow a rapid return of the bus to service.

Operation until first refueling with this change not completed poses little additional risk*to plant safety. Furthermore, it is our judgment that a loss-of-coolant accident coupled with an independent failure of a protective device occurring simultaneously during the agreed to extension in time is highly unlikely.

8.4.3 Containment Electrical Penetrations During a discussion with FP&L on April 1, 1983, a clarification of the indepen-dent primary and backup fault protection for each circuit penetrating contain-ment was developed. As a result of this clarification, the staff recognized a need to reassess the required compensating measures prior to FP&L completing their commitment to implement their design modifications as described in Sec-tion 8.4.3 of the SER. The staff's reassessment is described below.

St. Lucie 2 SSER 3 8-5

The design modifications on the majority of the*.affected circuits penetrating containment have yet to be implemented in the St. Lucie Unit 2 design. The applicant has committed to implement design modifications on most of these circuits by first quarter of 1984 and on the remainder by the first refueling outage. The applicant has provided the following'justification for operating the plant until these modifications are complete.

The low and medium voltage power systems (i.e., 480V, 4.16 kV, and 6.9 kV) are high impedance grounded. The predominant fault mode for such circuits is typically a single line to ground fault. For these circuits having a high impedance grounding system, ground fault currents would not result in unaccept-able degradation of the penetration assembly because the ground fault currents are much below the continuous current carrying capability of the penetration conductors.

FP&L has agreed to perform surveillance every four months on those as yet unmodified circuits which utilize molded circuit breakers by testing at least one of each representative type of molded circuit breaker used to protect containment electrical penetrations. We conclude that this action provides adequate assurance that the existing circuits with one protective device will function as designed. Further, it is the staff's judgment that occurrence of a LOCA, coupled with a three phase fault and an independent failure of a protec-tive device occurring simultaneously during this limited period is highly unlikely. The staff will verify the implementation of this design modification when it is completed.

8.4.6 Adequacy of Station Electric Distribution System Voltages We stated in Supplement 1 to the St. Lucie Unit 2 SER that the applicant has demonstrated by analysis that the transformer tap settings have been fully optimized for St. Lucie Unit No. 2 design. The results of these analyses have demonstrated that all Class lE loads are capable of being started and contin-uously operated over the expected grid voltage range. All voltages on the Class lE system will remain above the minimum acceptable design with the excep-tion of panel PP247 at 120 volt ac level. The applicant committed to correct unacceptably low voltage on panel PP247 to plant operation.

By letter of October 29, 1982, the applicant provided additional information on the above item. A voltage drop case was run utilizing as-built data for the new station service transformers and cable impedance based on actual installed cable length. The results of this analysis indicated that voltages on all Class lE buses including (power panel PP247) remain above 90% under steady state conditions with the full plant operating loads and minimum design switchyard voltages supplying the onsite system. This satisfies BTP PSB #1 position 3 and we find this to be acceptable.

• St. Lucie 2 SSER 3 8-6

9 AUXILIARY SYSTEMS 9.1 Fuel Storage Facility 9.1.3 Spent Fuel Pool Cooling and Cleanup System {Fuel Pool System)

In the SER, the staff noted that the FSAR stated that a second fuel pool heat exchanger will be installed by the first refueling. The reason was that there will be no spent fuel in the spent fuel pool until after refueling, at which time this*second heat exchanger could possibly be used.

The committed*action by the applicant was inadvertently considered by the staff to be a license condition. The staff corrected this based on the FP&L commitment.

9.1.4 Fuel Handling System In our SER input we stated that the applicant had not responded to a concern of lifting a load which weighs less than a spent fuel assembly with its handling tool over the spent fuel. Such a load could be lifted higher over the spent fuel than the height that a spent fuel assembly is normally transported over the spent fuel and therefore could potentially cause greater damage than that of dropping a spent fuel assembly.*

The applicant addressed this concern in a submittal dated September 3, 1982 and a clarification of the submittal in a meeting on October 21, 1982. The fuel handling building assumed the complete release of radioactivity in one assembly through the open cask door in the fuel handling building. The applicant reviewed all objects which could be transported over the spent fuel storage rack or could be dropped from the fuel handling floor. None of the objects reviewed could damage more than one fuel assembly; thus, the fuel handling accident in the FSAR bounds the light load drop accident.

Thus, we conclude that the requirements of General Design Criterion 61, 11 Fuel Storage *and Handling and Radioactive Control, 11 are satisfied.

Also in our SER we stated that the applicant had committed to implement the heavy loads guidelines interim actions prior to the .final implementation of the NUREG-0612 guidelines and prior to the receipt of the operating license.

Regarding this matter, the applicant had made two submittals. One submittal dated August 5, 1982 includes the final implementation of Phase I of NUREG-0612.

The other submittal dated September 21, 1982 includes a Phase I supplement and Phase II of NUREG-0612. Our review of the applicant's submittals is continuing.

However, we will require that a condition be placed in the license requiring

1) that prior to startup following the first refueling outage, FP&L shall con-form with the guidelines of Section 5.1.1 of NUREG-0612 {the six-month response to the NRC generic letter dated December 22, 1980) and 2) prior to startup fol-lowing the second refueling outage, FP&L shall have made commitments acceptable to the NRC regarding the guidelines of Sections 5.1.2 through 5.1.6 of NUREG-0612

{the nine-month responses to the NRC generic letter dated December 2~, 1980).

St. Lucie 2 SSER 3 9-1

9.5 Other Auxiliary Systems 9.5.l Fire Protection 9.5.1.3.a Penetration Seals In our SSER, we indicated that the applicant had not provided the necessary information to verify that the penetration seals were qualified for a fire resistance of 3-hours. By letters dated August 13, 1982 and October 28, 1982, the applicant provided additional information to verify the fire resistance of the penetration seals. We have reviewed the test results and find that the penetration seals are qualified for a fire resistance of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> in accordance with ASTM E-119 and, therefore, meet our guidelines.

Based on the test results, we conclude that the penetration seals meet the guidelines of Appendix A to BTP ASB 9.5-1 Section D.3(d) and are, therefore, acceptable.

• 9.5.1.6 Fire Protection for Safe Shutdown Capability A. Safe Shutdown Capability By letters dated April 1, May 17, Augu~t 10 and October 7, 1982, the applicant provided information concerning fire protection for the safe shutdown capability in accordance with the guidelines of Appendix R.

• The applicant's safe shutdown analysis states that systems needed for hot shutdown and cold shutdown consist of redundant systems and that one of the redundant systems needed for safe shutdown would be free of fire damage by pro-viding separation, fire barriers. arid/or alternative shutdown capability. For hot shutdown, the following shutdown systems would be required:

1. Diesel Generators A and B

2. Auxiliary Feedwater Systems A, Band C

3. Chemical and Volume Control System, including charging pumps A, Band C

4. Pressurizer Heaters A and B

5. Electric Equipment Room Supply and Exhaust Fans A and B

6. Power Roof Ventilators

7. Primary Water Pump 2A and 28

8. Lighting Panels LP227, LP228, LP216 and LP226

9. Station Battery Chargers A, Band AB

10. Station Batteries A and B

11. Instrumentation Inverters A, B, C and D

12. Instrumentation: Pressurizet Pressure A, B, C and D Pressurizer Level A and B

• RCS Temperature TE-115 and TE-1125 Steam Generator Pressure A, B, C and D Steam Generator Level A, B, C and D Condensate Storage Tank Level A and B BAMT Level LT-2206 and LT-2208 AFW Pump Flow A, Band C St. Lucie 2 SSER 3 9-2

13. Refueling Water Tank

14. Atmospheric Dump Valves A and B

15. Main Steam Isolation Valves A and B

16. Main Steam Isolation Bypass Valves A and B

17. Turbine Stop Valves

18. Hot Shutdown Panel For cold shutdown, the following additional equipment would be required:

1. ECCS Supply Fans A and Band Exhaust Fans A and B

2. Control Room Air Conditioning A, Band C

3. Instrumentation: CCW Pump Flow A and B

!CW Pump Flow A and B ECCS Exhaust Fan Flow A and B LPSI Pump Flow A and B

4. Low Pressure Safety Injection Pumps A and B

5. Shutdown Cooling Systems A'and B

6. Core Spray Block Valves A and B

7. Safety Injection System Block Valves A and B

8. Safety Injection Tank Vents

9. CCW Systems A, Band C

10. !CW Systems, A, Band C The safe shutdown analysis considered components, cabling and support equipment for systems i~entified above which are needed to achieve shutdown.

The applicant's safe shutdown analysis utilized cable and conduit lists for all rooms of the plant housing safe shutdown equipment to ensure that at least one train of this equipment is available in the event of a fire in any of these rooms. Safe shutdown equipment cabling was identified and traced through each fire area from the components to the power source. Additionally, all cables are protected by fuses; therefore, no fire-induced failure could affect shutdown because of either a common power supply or a common enclosure. The applicant stated that no induced spurious operation would affect shutdown. We have reviewed the applicant's method of analysis and audited several arrangement drawings to verify the correct application of the analysis methods.

We conclude that the applicant has provided an acceptable means of demonstrating that separation and/or barriers exist between redundant safe shutdown system trains.

While the applicant's methods of separation analysis are correct, the applicant has in certain fire areas requested deviations from meeting Appendix R require-ments. The deviations are evaluated in Section 9.5.1.6C of this report.

The applicant stated that alternative shutdown measures were not necessary for the control room. Notwithstanding, the applicant has provided a hot shutdown

• panel for the event of a fire disabling the control room. The remote shutdown control panel is located in a separate fire protected area in the control com-plex and provided an alternative to providing fire protection separation in the control room (refer to Section 7.4.3 of the SER).* The control functions and indications provided at the remote shutdown panel which are necessary for safe shutdown are electrically isolated or otherwise separate and independent from St. Lucie 2 SSER 3 9-3

the control room. Refer to Section 9.5.1.6B of this SER for further discussion on the alternative shutdown capability.

Based on the above, we conclude that the systems to be utilized for safe shut-down un_der fire events are acceptable.and the methodology used to assure adequate protection of safe shutdown .systems in accordance with Section 111.G of Appendix R is acceptable.

B. Alternative Shutdown Capability_,

Section 7.4.1.4 of the Final Safety Analysis Report (FSAR) describes the hot shutdown control panel 1 s design and*~apability. fhe design objective of the remote shutdown panel is to achieve and maintain hot shutdown from outside of the control room. The design of the remote shutdown control panel provides the capability to electrically isolate the control functions and indications for the shutdown systems from the control room. The systems necessary to achieve cold shutdown can be controlled from outside of the control room should a fire disable the control room .

. The design of the shutdown control panel was reviewed *to determine compliance with the performance goals outlined in the guidelines of Section 111.L of Appendix R. Reactivity control is accomplished by a manual scr~m before the operator leaves the control room and boron addition via the chemical and volume control system (charging pumps). Reactor coolant makeup is also provided by a portion of the chemical and volume control system. Reactor decay heat removal in hot shutdown is provided through the steam *generator by the auxiliary feedwater system.and atmospheric dump valves and in cold shutdown by the shutdown cooling system and the ultimate heat sink. *Pressurizer water level and pressure, steam generator pressure and water level, reactor coolant temperature, shutdown cooling temperature, source range monitor, and diesel generator voltage and power are among instrumentation available at the hot shutdown control panel to provide direct reading of process variables. The source range monitor is not currently isolable from the contrd~ room. However, during a meeting on October*21, 1982, the applicant agreed-to provide isolation for the source range monitor as a backfit task.

Isolation was scheduled to be done prior to startup following the first refueling.

The applicant noted that the reason for first refueling is because of the critical demand on electrical construction trades and the priority inflexibility of safety-related hardware presently being installed.

The staff considers that first refueling is acceptable because a fire in the control room that could potentially disable the source range monitor circuit is a highly unlikely event since the control room is continually manned. Even if the highly unlikely event occurred to disable the source range monitor circuit, there is an indirect means of measuring core reactivity by sampling the boron content in the primary coolant.

Based on the above, we conclude that the instrumentation outs'ide of the control room, and, therefore, the alternative shutdown capability, complies with the guidelines of Section 111.L of Appendix Rand is, therefore, acceptable.

St. Lucie 2 SSER 3 9-4

C. Appendix R Deviations In our SER, we stated that the applicant's fire protection program will meet the technical requirements of Appendix R to 10 CFR 50. By letters dated July 14 October 28, 1982, and February 25, 1983 the applicant proposed 31 deviations from the technical requirements of Appendix R.

The applicant has requested 15 deviations from installing 3-hour fire rated doors and dampers in exterior wall penetrations in the Reactor Auxiliary Building, Diesel Oil Storage Building and.the Diesel Generator Building. The staff reviewed the licensee's requests and find that the exterior walls in these buildings do not separate redundant safe shutdown equipment and no fire hazards exist within 50 feet of these buildings. **Therefore, no deviations from our guidelines are needed.

The following are the remaining 17 deviations:

1.Section III.G.2 (Penetrations In Three-Hour Fire-Rated Barriers)

The applicant has requested deviations from providing 3-hour fire-rated dampers in ventilation ducts penetrating 3-hour fire rated barriers used to separate redundant trains in the following areas:

1 duct penetrating the wall between the Pipe Tunnel and Division A Cable Penetration Area.

3 ducts penetrating the wall between the Electrical Equipment and Supply Fan Room and the Control Room.

• 1 duct penetrating the wall between the Component Cooling Water Surge Tank Room and the Control Room.

6 ducts penetrating the wall between the Shutdown Heat*Exchanger Room and the Corridor on the 0.50 feet elevation of the Reactor Auxiliary Building.

a. Penetration Between the Pipe Tunnel and Division A Cable Penetration Area The Division A Electrical Penetration Area is located at EL 19.50 ft.in the northwest section of the Reactor Auxiliary Building. The area is separated from adjacent areas by walls, floor and ceiling having a fire resistance rating of greater than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

The combustible fuel loading for this relatively small room (540 sq ft) is greater than 2 hrs consisting mostly of cable insulation.

Ionization smoke detection is provided throughout the fire zone as well as a preaction sprinkler system is provided throughout the zone. Fire extinguishers and hose stations* are provided in the immediate area.

The duct penetration in question is located in the.east wall approximately 18 ft above the floor. All other ducts that pass through the walls of this fire zone have installed fire dampers. The pipe tunnel to which the duct passes St. Lucie 2 SSER 3 9-5

through is a high radiation area and personnel access is very limited~ The fuel load in the area is low.

The applicant states that the installation of the 3-hour fire rated damper in ventilation duct penetrating the subject rooms would not significantly enhance fire safety.

The installation of the 3-hour fire-rated dampers is intended to prevent the spread of fire from one area to another. Since each area contains early warning detection and the fuel loading in the Pipe Tunnel is low and the heavy fuel load in the Division A Cable Penetration Area is protected with automatic sprinklers, we agree with the applicant that a fire would not propagate from one area to the other.

Based on our evaluation, we conclude that the installation *of the 3-hour damper in the ventilation duct penetration between the Division A cable penetration area in the pipe tunnel would not significantly increase the level of fire safety. We find the deletion of the 3-hour damper to be an acceptable deviation from Section 111.G.2 of Appendix R. Therefore, the fire protection provided for these areas. is acceptable.

b. Penetration Between the Electrical Equipment Supply Fan Room.

and Control Room Electrical Equipment Area Supply Fan Room is separated from the adjacent Control Room complex by reinforced concrete and concrete block walls, concrete floor and ceiling having fire resistive ratings greater than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The area contains two redundant Supply Fans (2 HVS-5A and 2HVS-5B) and associated electrical equipment. The discharge ducts from the supply fans pass through the floor opening to reach the Division B Switchgear Room. *Fire dampers are not provided in this duct.

Division B Swtichgear Room is directly below the area, and has a combustible loading of approximately 2*hrs. The Division.B Switchgear Room does not have an automatic fire suppression system.

Large ventilation ducts penetrate the wall between the Electrical Equipment Supply Fan Room and Control Room at three locations.

It was our concern that a fire in the Division B Switchgear Room could produce a significant amount of hot gases which could enter the Electrical Equipment Supply Fan Room thro~gh the unprotected duct penetration in the floor, and enter into the control room, if the a duct into the control room collapses. At our*request, the applicant committed, by letter dated November 4, 1982, to wrap the entire length of the ducts in the Electrical Equipment Supply Fan Room which penetrate the Control Room Walls to provide a one hour fire resistance rating. This will protect the ducts from collapsing, and therefore, we find this modification acceptable.

• Based *on our evaluation and the applicant's commitment, we conclude that the installation of 3-hour dampers in the ventilation ducts penetrating the wall between the Electrical Equipment Supply Fan Room and Control Room would not significantly increase the level of fire safety. We find the deletion of the St. Lucie 2 SSER 3 9-6

3-hour dampers to be an acceptable deviation from Section III.G.2 of Appendix R. Therefore, the fire protection provided for these areas is acceptable.

c. Penetration Between the Component Cooling Water Surge Tank Room and Control Room The Component Cooling Water Surge Tank Room is located on elevation 63 feet of the Reactor Auxiliary Building adjacent to the Control Room. The area is sepa-rated from the Control Room by a 3-hour fire-rated barriers with the exception of one ventilation penetration. The fuel load in the Component Cooling Water Surge Tank Room is negligible. *

. The applicant states that the installation of a 3-hour rated damper in the sub-ject ventilation ducts would not significantly enhance fire safety.

The installation of a 3-hour fire-rated.damper is intended to prevent the spread of fire from one area to another.* Since the fuel loading in the Component Cooling Water Surge Tank and Control Rooms is negligible, we agree with the applicant that a fire of significant extent should not occur within the rooms and, therefore, would not spread from one area to the other.

Based on our evaluation, we conclude that the installation of the 3-hour damper in the ventilation duct penetrating the wall between the Component Cooling Water Surge Tank Room and Control Room would not significantly increase the level of fire safety. We find the deletion of the 3-hour damper to be an acceptable deviation from Section III.G.2 of Appendix R. Therefore, the fire protection provided for these areas is acceptable.

d. Penetrations Between the Shutdown Heat Exchanger Room and the Corridor on the 0.50 feet elevation ~of the Reactor Auxiliary Building The shutdown heat exchanger area, is located in the Reactor Auxiliary Building (RAB) at El. 00.50 ft between column lines RAK/RA! and column line 2RA12 ana a reinforced concrete wall 8 ft north of column line 2RA3. The area is separated from adjacent areas by full height concrete walls, a concrete floor and ceiling, all having a fire barrier rating greater than 3 hrs.

Combustible loading in the area will be negligible. Ionization detectors will be provided throughout the area. The corridor on the 0.5 feet elevation of the Reactor Auxiliary Building is located on the opposite side of the wall with the ventilation penetrations and has a negligible fuel loading. Ionization smoke detection will be provided throughout the area, and an automatic preaction sprinkler system will be provided for heavily cabled areas. The preaction system will also be provided over each of the ventilation penetrations in this wall. Fire extinguishers and hrise stations will be provided in the immediate area.

The applicant states that the installation of the 3-hour fire-rated dampers in the ventilation duct penetrating in the subject walls would not significantly enhance fire safety.

St. Lucie 2 SSER 3 9-7

The installation of the 3-hour fire-rated dampers is intended to prevent the spread of fire from one area to another. Since the fuel loading in the areas is negligible, and automatic sprinkler and smoke detection has been provided, we agree with the applicant that a fire of significant extent would not propagate from one area to another.

Based on our evaluation, we conclude that the installation of 3-hour dampers in the ventilation ducts penetrating the wall between the Safe Shutdown Heat Exchanger Room and the Corridor on the 0.5 feet elevation of the Reactor Auxil-iary Building would not significantly increase the level of fire safety. We find the deletion of the 3-hour damper to be an acceptable deviation from Section III.G.2 of Appendix R. Therefore, the fire protection provided for these areas is acceptable.

2.Section III.G.2 (Penetrations In Three Hour Fire Rated Floor Ceiling Assemblies)

The applicant has requested deviations from sealing three hatch openings in 3-hour fire-rated barriers separating redundant trains in the Reactor Auxiliary Building. One hatch is located at column lines RAJ and RAS.

The opening runs between elevations 0.5 ft to 43 ft. The other hatch is located at column lines RAC and RA4 and the opeii","iig runs between elevations 0.5 and 19.5 ft Steel plates,~ inch thick, are used to cover the hatch openings at each elevation. The openings *are protected with early warning fire detection and automatic sprinklers. There is a negligible concentration of combustibles in the immediate area of the hatch openings.

Because the hatch openings are covered with noncombustible covers, automatic detection and fire suppression have been provided, and concentration of combus-tibles is negligible beneath the hatch opening,,we find the probability of a fire which could propagate from one floor level to the other level is low.

Based on our evaluation, we conclude that 3-hour penetration seals in lieu of the hatch covers would not significantly increase the level of fire safety. We find the deletion of the seals to be an acceptable deviation from Section III.G.2 of Appendix R. Therefore, the fire protection provided for these areas is acceptable.

3.Section III.G.2 (Three Hour Fire-Rated Barriers)

The applicant has requested deviations from providing 3-hour fire-rated barriers to separate redundant trains in the following areas:

- Redundant Heat Exchangers

- ECCS Room .

- Charging Pump Area

a. Redundant Heat Exchangers The applicant requested a deviation from Section III.G.2 of Appendix R because a full height 3-hour rated barrier is not provided between the redundant shutdown heat exchangers.

St. Lucie*2 SSER 3 9-8

The shutdown heat exchanger area is located in the Reactor Auxiliary Building at elevation 0.50 ft between column lines RAK/RA! and column line 2-RA12 and a reinforced concrete wall 8 ft north of colmn line 2-RA3 . . The area is separated from adjacent fire areas by full height concrete walls, a concrete floor and ceilin~, all having a fire barrier rating greater than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

The area is divided into two compartments by a partial 8 ft high full length 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire rated concrete wall that separates the two redundant shutdown heat exchangers.

• Due to the nature of the equipment as well as the only combustibles in the area being transients, a fire in the area would not directly impinge upon or radiate heat directly on the heat exchangers.

Based on our evaluation, we conclude that the installation of 3-hour barrier between the Shutdown Heat Exchangers would not significantly increase.the level of fire safety. We find the deletion of the 3-hour barrier to be an acceptable deviation from Section III.G.2 of Appendix R. Therefore, the fire protection provided for this area is acceptable.

b. ECCS Room The applicant requested a. deviation from Section III.G.2 of Appendix R because a full height 3-hour rated fire barrier is not provided between the redundant shutdown coo1ing pumps.

The*ECCS Pump room, located in the RAB at El. (-)10.00 ft, has been separated into two zones each containing train A and B redundant safety equipment. The two zones are separated by a partial height wall, ranging in height from 9.5 ft to 20 ft. (20 ft. from column lines RAI to RAG and 9.5 ft. from column lines RAG to RAE). Each zone contains one Low Pressure Safety Injection Pump (LPSI),

one Containment Spray Pump, and one High Pressure Safety Injection Pump. Only one LPSI Pump is required for safe shutdown. The valves, operators, push--

button stations, instrumentation and electrical boxes for each redundant system are also located in the same zone as their associated equipment.

The area contains a negligible fuel loading. The area is provided with ionization smoke detectors. Fire extinguishers and hose stations are provided in the immediate area.

The redundant LPSI pumps are physically separated by more than 20 ft .. However, the separation distance of the cables associated with these pumps in some loca-tions is less than 20 ft. The cables not separated by 20 ft which run above the partial barrier will be enclosed in a I-hour fire-rated .barrier.

Because the amount of in situ combustibles is negligible, and an early warning detection is provided, we judge that a fire which could cause damage to redundant trains is unlikely. The installation of a 3-hour fire barrier between the LPSI pumps or the installation of an automatic fire suppression system in the area St. Lucie 2 SSER 3 9-9

would not significantly increase the level of fire safety. Therefore, we find that the existing level of fire protection provides reasonable assurance that one train of safety systems will be free of fire damage after a fire.

Based on the above evaluation, we conclude that the existing fire protection is adequate, the deletion of the 3-hour fire barrier in the ECCS room between the LPSI pumps is an acceptable deviation from Section III.G.2 of Appendix R.

c. Charging Pumps The applicant requested a deviation from Section III.G.2 of Appendix R because a full height 3-hour rated fire barrier is not provided between each of the three charging pumps.

The Charging Pump area is located in the Reactor Auxiliary Building at

• elevation 00.50 ft. This area is separated from adjacent areas by full height reinforced concrete and concrete block walls, concrete floor and roof, all having a greater than 3-hour fire rating. Ceiling height is approximately 20 ft. This area is divided into three zones by partial height 10 feet concrete block walls, separating the three charging pumps from each other and the common hall. The distance between adjacent charging pumps is approximately 10 feet.

Ionization type smoke detectors are installed throughout the area. Fire extinguishers and hose stations are located in the immediate area. An automatic reaction sprinkler_system has been provided in the charging pump cubicle access corridor.

The combustible in the area is the 10 gallons of lubricating oil contained in each charging pump. The lubricating oil comprises a fuel load of 7000 BTU/sq ft, which if totally consumed, would correspond.to approximately a 5-min fire on the ASTM E-119 standard time temperature curve.

Because the amount of in-situ combustibles is small and an early warning detec-tion is provided, we are of the opinion that a fire which could cause damage to redundant trains is unlikely. The installation of a 3-hour fire barrier between the charging pumps or the installation of an automatic fire suppression system in the area would not significantly increase the level of fire safety.

Therefore, we find that the existing fire protection level provides reasonable assurance that.one train of safety systems will be free of fire damage after a fire.

Based on the above evaluation, we conclude that the existing fire protection is adequate, the deletion of the 3-hour fire barrier between the charging pumps is an acceptable deviation from Section III.G.2 of Appendix R.

4.Section III.G.2 (Automatic Fire Suppression System)

The applicant has requested deviations*from providing automatic fire suppression systems in the following areas:

- Division A Switchgear Room

- Division B Switchgear Room

- Hallway to the Division B Fan Room Elevation 43 Feet Reactor St. Lucie 2 SSER 3 9-10

Auxiliary Building

- Component Cooling Area

- Steam Tressel Intake Structure

- Aerated Waste Storage Tank Room

- Gas Decay Tank Cubicle 2C Each of the above areas contains early warning fire detection. Redundant safe shutdown cable and equipment is separated by more than 20 feet or enclosed in a fire rated barrier. The fuel load in each of the above areas is low with the exception of the Division A and Division B Switchgear Room. The fuel load in the Division A & B Switchgear Room has fire severity of 1.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. In these areas, the redundant cables will be enclosed in a 2-hour fire rated conduit barrier.

Because the in-situ fuel loads are low, or redundant systems have either adequate separation, or have been enclosed in fire rated barriers with an hourly rating higher than the fire.severity of in-situ combustibles, and early warning fi.re detection is provided, we have reasonable assurance that after a postulated fire in any of these areas, one train of safe shutdown systems will be free of fire damage.

Based on our evaluation, we conclude that the in~tallation of automatic fire suppression system in the Division B Switchgear Room, Hallway to the Division B Fan Room, Component Cooling Area, Steam Tressel, Intake Structure, Aerated Waste Storage Tank Room and Gas Decay Tank Cubicle 2C would not significantly increase the level of fire safety. We find the deletion of the automatic fire suppression systems to be an acceptable deviation from Section III.G.2 of Appendix R. Therefore, the fire protection provided for these areas is acceptable.

5.Section III.G.3 (Fixed Suppression System)

The applicant requests a deviation from providing a fixed suppression system in the control room. The control room has a fire detection system, hose station, and fire extinguishers. An alternate safe shutdown system is also available for the control room. The room is continuously manned and the fire load in the control room is low.

Because the fire hazard is light, and the control room continuously manned, there is reasonable assurance tha a fire would be promptly extinguished.

Based on our evaluation, we conclude that the installation of a fixed suppression system in the control room would not significantly increase the level of fire safety. We find the deletion of the fixed suppression system to be an acceptable deviation from Section III.G.3 of Appendix R. Therefore, the fire protection provided for the control room is acceptable.

6.Section III.G.2 (Separation)

For the annular volume inside containment, the applicant has requested a deviation from providing separation between redundant trains (cable trays) of either 20 ft horizontal distance free of intervening combustibles or a non St. Lucie 2 SSER 3 9-11

combustible* radiant heat shield or of*providing an automatic fire suppression system.

In this area, redundant cable trays are on each side of the annulus at several elevations. The ceiling is very high, i.e., the top of the containment. There are no solid floors in the annulus and gratings are provided at several eleva-tions for personnel access. At some locations, cables are contained in conduit and cross over cable trays of a redundant division. Redundant safe shutdown trays are separated horizontally ~y 7 ft free of inte~vening combustible.

Early warning fire detection is provided in the area. Cables in the area are qualified to IEEE-383 flame test. All cables trays have solid bottoms; all instrument cable trays are covered.

• By letter dated October 28, 1982 the licensee committed to install noncombustible radiant energy shields beneath the lowest redundant Division A and Division B cable trays at each elevation and to enclose all safe shutdown cables installed in conduit that are not separated from the redundant cable trays by 20 ft, in a 1-hour fire-rated barrier.

Due to the restricted access to this area, an exposure fire from the accumula-tion of transient combustibles which could cause damage to redundant cables is unlikely. The noncombustible radient energy shields installed beneath the lowest cable tray of each redundant division will divert the hot gas plume from the cable and the high ceiling will prevent stratification of the hot gases.

Therefore, there is reasonable assurance that one train of safe shutdown systems will be free of fire damage.

Based on our evaluation, we conclude that for the annular volume within the containment the proposed alternative provides an acceptable level of fire protection.

9.5.1.11 Fire Protection Program License Conditions (a) Sprinkler Systems, Cable Rerouting, Dampers, Emergency Lights, RCP Lube Oil and Fire Barriers Our guidelines recommend that the fire protection program for an entire reactor unit should be fully operational prior to initial core load. Our SER also recommended that the fire protection program be operational prior to core load.

By letter dated October 1982 the applicant requested deviations from not completing the installation of sprinkler systems, cable rerouting, instal-lation of barriers, installation of dampers and installation of emergency

• lights until the first refueling outage and the installation of the reactor coolant pump lube oil collection system until initial criticality. By memo-randum dated November 12, 1982, we granted the applicant's request for not completing the installation of the RCP oil collection system until initial criticality. We denied the remainder of the deviation requests and recommended that the items be completed by the 5% power milestone and that the plant Tech-nical Specifications action statements be implemented between core load and 5%

power for the items not completed. This interim measure is equivalent to having the equipment installed but inoperable which will require the plant to meet the Technical Specification action statement.

St. Lucie 2 SSER 3 9-12 t

By letter dated February 9, 1983, the applicant identified in Table 9-1 the fire protection items to be completed prior to exceeding 5% power.

The applicant committed to implement the applicable plant Technical Specifica-tion action statements. Each of the areas listed in Table 9-1 contains early warning fire detectors, manual hose stations and portable fire extinguishers all of which w'ill be operational prior to core load.

Because the fission. product inventory i'.n* the core is not appreciable and there-fore the health and safety of the public is not affected, and based on the appli-cant's commitment to implement the plant Technical Specifications action state-ments, we find adequate fire protection measures have been provided. Therefore, the applicant's request for the items listed in Table 9-1 be completed prior to exceeding the 5% power should be granted.

• As noted above, Florida Power and Light Company (FP&L) is installing a sprinkler system under a schedule such that all operable sprinklers will be in place prior to achieving 5% power. However, installation of the seismic support and restraints will not be completed until October 1983 and FPL has requested per-mission to operate for a period of six months while the seismic support and.

restraints are installed.

FP&L's justification for interim operation is based on the following arguments.

1. The strongest historical ground motion at the site was probably Modified Mercalli (MM) intensity IV-V from the 1886 Charleston, South Carolina earthquake.

2. They estimate that the peak acceleration from an intensity VI earthquake near the site would be 0.05g and that probabilistic analysis indicate that the probabilility of occurrence of this size event is once per 3000 years.

3. Earthquakes in Florida have been infrequent of low to moderate intensity (MM III-IV) and have epicenters at least 100 miles from the St. Lucie site.

4. The Uniform Building Code designates the site vicinity as Zone O which is considered to be a zone of no earthquake damage.

5. The occurrence of an ear.thquake which could damage the sprinkler system in the RAB is extremely unlikely during the short duration (approximately 6 months) when the sprinkler systems are being seismically restrained and supported.

FP&L did not provide any information as to the ability of the sprinkler system to withstand seismic motion prior to the completion of the installation of the restraints and supports.

The Geosciences Branch staff has reviewed the FP&L.justification and the per-tinent seismologic literature and determined the following:

., I St. Lucie 2 SSER 3 9-13

1. There is no record-of the effect of the Charleston earthquake in the St. Lucie area. However, a study by Bollinger (Ref. 1) suggests an intensity of MM Vin the St. :Lucie area due to the 1886 earthquake.

. '1

2. Using the trend of the mean*s of the Trifunac and Brady (Ref. 2) relation between peak horizontal ground-acceleration and MM intensity results in an estimate of peak ground acceleration of about 0.07g from an MM intensity VI earthquake near the site. 1

3. Probabilistic estimates for this area show very low seismic hazard, for example, Algermissen and Perkins (Ref. 3) and the Applied Technology Council (Ref. 4) indicate accelerations of less than 0.04 or 0.05g associated with*a return period of.475 years. A recent study, Algermissen and others (Ref. 5) estimates a return period of about 2500 years for an acceleration of about 0.04g in the St. Lucie area.

4. The nearest historical earthquake epicenter was about 100 miles from the site and this was a maximum MM V event.

Although we do not know the ability of the non-seismically qualified sprinkler system to withstand seismic motion, the information presented by the applicant and the information gathered by the staff indicating the low level of seismic activity in the site area (the safe shutdown earthquake is only O.lg) leads us to the conclusion that the likelihood of significant earthquake ground motion at the site during a six month period is so small as to allow interim operation of the plant. If, however, the seismic restraints and support for the sprinkler system are not completed by October 1983 we recommend that FPL be required to provide a simplified seismic analysis of the existing system to justify con-tinued operation.

By letter dated February 9, 1982, the applicant also requested a deviation from our guidelines to operate the plant without completing the installation of flame impingement shields inside of containment until the first refueling outage. This is evaluated in Section 9.5.1.ll(b) below.

(b) Reactor Containment Building Cable Tray Flame Impingem~nt Shields In*a letter dated October 8, 1982, FP&L submitted a list of engineering and construction tasks that were not expected to be completed by the end of first refueling. The list'identified several sections of the Fire Protection Pro-gram. The staff reviewed the FP&L justification for not completing these items and determined that the basis was unacceptable.

• After numerous discussions with FP&L, an approach was agreed upon between FP&L and the staff (refer to Section 9.5.1.ll(a) above) for completing nearly all of the Fire Pro'tection Program by 5% power. .

FP&L identified two items, the isolation of the source range monitor, which is located at the hot shutdown control panel, from the control room and the reactor containment building (RCB) cable tray flame impingement shields, that will not be completed by 5% power. FP&L. has committed to isolate the source range monitor at first refueling. The staff review of this is provided in Section 9.5.1.GB above. This item is noted here because it is also part of the Fire Protection Program License condition. FP&L cited insufficient time to complete the shields because of the large effort involved in doing the following:

St. Lucie 2 SSER 3 9-14

(1) compilation of as-built data on two hundred affected cable tray supports, (2) re-analysis .of 50 typical tray supports (determined from (1) above) to ensure that the seismic qualification of the trays is maintained, (3) detailed design of the flame shield support frame, (4) development of reinforcing details on an estimated 30 typical cable tray support designs needing modification,* and (5) upgrade o~ drawings, issue of sketches and plant change modifications.

In addition to the time and effort involved in the items described above, the following construction schedule constraints exist:

(1) there is a shortage of craft necessary to install approximately 1100 linear feet of shielding, and

. (2) once the core is loaded, construction activities within the RCB are going to be restricted due to cleanliness and security requirements.

FP&L noted that the shields in the RCB will be installed prior to first refuel-ing and the justification for operating the reactor prior to installing the shields is as follows:

(1) FP&L will augment existing administrative procedures to require an additional final surveillance of those affectd cable tray areas for any sources of combustibles.

(2) Affected detectors will be tested to show operability during any unscheduled outages that may occur in the .interim. (Unscheduled outages are defined as the plant being in Mode .5 for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.)

(3) Affected area hose stations will be checked prior to closing containment and during any unscheduled outages.

(4) The containment contains 2.5 million cubic feet of free volume. This massive area basically categorizes the containment as an outdoor area with regard to a fire .. It prevents hot gas stratification and reduces radiant heating effects, thus greatly reducing the potential damage of a fire. *

(5) The reactor coolant pumps have an oil collection system. With the excep-tion of the cables, the reactor coolant pump oil system is the only other major source of in-situ combustibles in containment. The system is designed to remove the combustible as. a fire hazard containment. In addi-tion, the reactor coolant pump oil reservoirs are provided with a level indication and alarm in the control room which would identify to an operator that a potential fire hazard may exist. Also, FP&L will walkdown the oil collection system prior to closing the containment to assure the systems integrity.

(6) FP&L will install flame retardant blanket shields in the RCB on the bottom tray for each cable tray stack whose bottom tray contains cables needed for St. Lucie 2 SSER 3 9-15

safe shutdowns. Specifically, these shields will be installed below the lowest tray. in each stack. FP&L estimates that this involves about one third of the .1100 linear feet of cable tray bottoms to b~ covered. Where the remaining two thirds of the bottom tray in each stack contains no essential cables for safe shutdown, the tray will be utilized as radiant shields to the safety-related cable trays in the stack above. These flame retardant blankets will be installed prior to exceeding 5% power.

The staff finds tne basis acceptable for allowing the plant to operate until the shields are installed prior to first refueling. The staff notes that the RCB is generally considered a less likely fire area because of restricted access and with the additional administrative control to preclude solid transients, further assurance is provided to prevent fires within the RCB.

To be certain that FP&L will commplete the installation prior to first refueling, a condition will be placed on the license for FP&L to meet the following .design, procurement and installation schedule:

Action Date 1.. Purchase and receive the flame impingement shield material needed to complete the work By 5% power

2. Purchase and receive the steel needed to complete the work By 5% power

3. Complete field engineering work By 5% power

4. Complete design engineering work By 5% power

5. Pre-cut steel and flame impingement shield By 9/1/83

6. Installation of the flame impingement shields By 1/84 9.5.2 Communication Systems 9.5.2.1 Intraplant Systems 9.5.2.lD Sound-Powered System The applicant's submittal of May 4, 1982 noted that the installation completion and ope rat ion of the sound-po*wered system is being de 1ayed to prior to exceeding 5% power due to a shortage of critical electrical trades .. The applicant stated that plant operation is justified without the use of this system because of the extremely remote likelihood for its need in the two-month interval between core load and 5% power and the several existing intraplant communication systems available for the same time period.

The staff finds the justification acceptable and agrees with allowing _the plant to operate to 5% power at which time the system must be completed and operable.

St. Lucie 2 SSER 3 9-16

The staff initially considered this as an item for which a condition would be included in the operating license to assure that NRC requirements will be met.

Subsequently, when it was recognized that the Technical Specifications, which is Appendix A of, the operating license, has a communication requirement which includes this system, the staff decided it was unnecessary to make this item an operating license condition.

9.5.4 Emergency Diesel Engine Fuel Oil Storage and Transfer Syste~

9.5.4.1 Emergency Diesel Engine Auxiliary Support Sytem (General)

In the SER the heavy duty turbocharger drive gear assembly modifiction to the diesel generator was identified to be implemented prior to startup following the first refueling. Also, in Section 1.9, of the SER, this item was listed as a license* condition. Since the SER was published, the applicant, prior to core load, completed the modification and this was verified by Region II.

Therefore, this item has been removed from the list of license conditions.

9.5.7 Emergency Diesel Engine Lubricating Oil System In the SER, the diesel generator lube oil modification was identified in Section 9.5.4.1 and in Section 9.5.7.

In Section 1.9 (License Conditions) of SSER 2, this redundancy was inadvertent-ly overlooked and the item was listed twice as though it were two separate and independent license conditions. Therefore, the redundancy was eliminated by deleting the listing and the reference to Section 9.5.7 in Section 1.9.

9.6 References

1. Bollinger, G. A., 1977, Reinterpretation of the Inte.nsity Data for the 1886 Charleston, South Carolina Earthquake, in Studies Related to the Charleston, South Carolina Earthquake of 1886 - A Preliminary Report, USGS Prof. Paper 10288.

2. Trifunac, M. 0. and A. G. Brady, 1975, On the Correlation of Seismic Intensity Scales with Peaks of Recorded Strong Ground Motion; Bull, Seis. Soc. Am., v. 65, No. 1, pp. 139-162. *

3. Algermissen, S. T. and D. M. Perkins, 1976, A probabilistic estimate of maximum acceleration in rock in the contiguous United States, USGS Open File Report 76-416.

4. Applied Technology Council, 1978, Tentative Provisions for the development of seismic regulations for buildings, National Bureau of Standard Special Publication 510.

5. Algermissen, S. T., D. M. Perkins, P. C. Thenhaus, S. L. Hanson, and B. L. Bender, 1982, Probabilistic estimates of maximum acceleration and velocity in rock in the contiguous United States, USGS Open File Report 82-1033.

St. Lucie 2 SSER 3 9-17

Table 9-1 Fire protection items to be completed by 5% power Applicable T/S Area

• Elevation Fire Zone Action Statement I. Sprinklers Reactor Auxiliary Building E-W Hallway -0.5 19/20 A*

Reactor Auxiliary Building A Elec. Penet. Room 11 11 19.5 22 A*

Reactor Auxiliary Building B Elec. Penet. Room 11 11 19.5 23 A*

Reactor Auxiliary Building Cable Spreading Room 43.0 52 A*

Reactor Auxiliary Building HVAC Room Hall 43~0 39 A*

Reactor Auxiliary Building Cable Loft & Hall 19.5 51 A*

II. Fire Rated Assemblies A. Barriers Reactor Auxiliary Building Stair Enclosure 19.5 ft 19/51 B*~

Reactor Auxiliary Building Stair Enclosure 19.5 ft 20/51 B**

Reactor Auxiliary Building Cable Loft 28.0 ft 51 B**

Reactor Auxiliary Building Cable Spread Room Wall 43.0 ft 34/52 B**

Reactor Auxiliary Building Hatch Cover 19.5 ft 20/51 B**

Reactor Auxiliary Building Hatch Cover 19.5 ft 19/51 B**

Reactor Auxiliary Building Hatch Cover 43.0 ft 51/34 B**

Reactor Containment Building Radiant Energy Shield 23-61 ft 14 B**

St. Lucie 2 SSER 3 9-18

Table 9-1 (Continued)

Applicable T/S Area Elevation Fire Zone Action Statement III. Barrier B. Wall/Floor Seals Reactor Auxiliary Building Walls/Floors 0.5-62 ft *** B**

Diesel Generator Building Common Wall N/A 8/9 B*~

Diesel Generator Building Storage Tank Common Wall N/A 1/2 B**

C. Circuit Rerouting Reactor Auxiliary Building Circuits 0.5-43 ft 22,23,51, B**

34,37,39,52, 15,16,20,24

.Reactor Containment Building 14 D. Fire Doors Reactor Auxiliary Building 0.5-62 ft 19,23,51, B**

34,52 E. Duct Wrap Reactor Auxiliary Building SA & B Fan Room 62.0 ft 48 B**

• A. Action:

With one or more of the above required sprinkler systems inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> establish a continuous fire watch with backup fire suppression for areas where systems required for safe shutdown could be damaged; for other areas, establish an hourly fire watch patrol.

• • B. Action:

With one or more of the above required fire rated assemblies and/or sealing devices inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> establish a continuous fire watch on at least one side of the affected assembly, or verify the OPERABILITY of the fire detectors on at least one side of the inoperable assembly and establish an hourly fire watch patrol.

• • • 15, 16, 17, 18, 19, 20, 24, 40, 21, 22, 23, 24, 26, 27, 28, 29, 30, 31, 33, 51, 34, 35, 36, 37, 38, 39, 50, 52, 42, 43, 44, 48, 15, 16, 20, 24 St. Lucie 2 SSER 3 9-19

10 STEAM AND POWER CONVERSION SYSTEM 10.2 Turbine Generator 10.2.1 Turbine Disc Integrity In*the SER, the staff decided that we will place a condition op the operating license to require that the applicant inspect the LP. turbine disc before start-up after the first refueling outage.

Subsequently, the staff decided that the LP turbine disc inspection can be appropriately included as part of an augmented inservice inspection section to the Inservice Inspection Program for Class 1, 2 and 3 components. The applicant will have as a license condition that the Inservice Inspection Program shall be submitted for staff review and approval six months after core load.

10.3 Main Steam Supply System 10.3.4 Secondary Water Chemistry In the SER, the staff decided that we will place a condition on the operating license to require that the applicant's proposed secondary water chemistry monitoring and control program be carried out. Subsequently, the staff *decided that this secondary water chemistry program can be met appropriately and equally by including it in the Technical Specification (TS); therefore, it will be included in the TS which is Appendix~ to the operating license.

10.4 Other Features of the Steam and Power Conversion System 10.4.7 Condensate and Feedwater System In Section 10.4.7 of the SER issued in October 1981, the staff noted that FP&L had committed to perform preoperational tests utilizing normal plant operating procedures to demonstrate the ability to restore steam generator level follow-ing a low level transient without causing unacceptable feedwater/steam generator water hammer. In Section 10.4.7 of SSER 1 issued December 1981, the staff clarified that listing water hammer testing as confirmatory in Section 1.8 of the SER was inadvertent since the staff had reviewed and found the FP&L pro-posed test program acceptable. Therefore, the staff considered this item resolved pending FP&L formal notification to the staff that the test indicated there was no water hammer problem.

In Section 1.9 of SSER 2 issued September 1982, water hammer testing was listed as a license condition. This occurred because the auto initiation auxiliary feedwater test, in which part of the testing is the water hammer test, will be performed after core load. FP&L had identified this to the staff in their May 4, 1982 letter (L-82-168) in which they stated that the auto initiation circuitry of the auxiliary feedwater system will not be in place by core load.

The staff found the changed schedule acceptable since the testing would be accomplished before the plant exceeded 5% power.

St. Lucie 2 SSER 3 10-1

Subsequently, the staff confirmed that the water hammer testing is part of the FP&L initial test program which is a licensed condition; therefore, a redundancy is eliminated by deleting water hammer testing as a separate license condition.

St. Lucie 2 SSER 3 10-2

11 RADIOACTIVE WASTE MANAGEMENT SYSTEM 11.2 Liquid Waste Management In a letter dated October 8, 1982 (L-82-434), the applicant noted an improve-ment in the scheduled date for implementing the design modifications for (1) the liquid radwaste pump interlocks to prevent the Primary Water Storage tank overflow, (2) addition of a control valve to prevent the Refueling Water Tank overflow.

These items were reviewed by the staff and documented in the St. Lucie, Unit No. 2, SER (Section 11.2). In that review, we accepted the FP&L proposal that these items will be installed as backfit items, subsequent to the plant startup, but not later than the completion of the first refueling. Delay in pump inter-lock and control valve addition was accepted because releases from even a tank rupture have been shown to be withiri allowable release limits and because operator action is likely to prevent any inadvertent tank overflow. Further-more, mixed fiss.ion and activation products build-up in the primary coolant during the first year of operation will be minimal and any residual radio-activity concentrations in the Refueling Water Storage Tank and Primary Water Storage Tank water will be negligible. Therefore~ we will accept the new FP&L proposal to complete the installation of these items by fourteen (14) months after the core load.

In Section 1. 9 of SSER 2 we 1i sted item (19) 11 Pracess Control P*rogram for wet radioactive solid waste 11 as a license condition. Subsequently, the staff decided that this requirement can be met appropriately and equally by including it in the Radiological Effluents Technical Specification (RETS); therefore, it will be included in the RETS which is Appendix A to the operating license.

In another matter dealing with concentrator bottoms tanks, the applicant provided in a letter dated May 4, 1982 (L-82-168) the following reasons for the delay in completion of the installation:

11 FPL 1 s present waste management scheme does not necessitate the use of the evaporators. FPL has had good results on St. Lucie 1 using ion exchange for the processing of liquid waste and this allows ship-ment of dewatered resins as the end product of this management scheme.

As a result of this experience, the waste concentrator evaporators will likely not be used for some time into the future, if ever. The bottoms tanks were added into the design late in the engineering phase during the FSAR review. This late addition has not allowed sufficient time to complete the design, procure the equipment and install it in the plant. The waste concentrator bottoms tank will be installed in the plant by first refueling. 11 The delay in completing the installation of the concentration bottoms tanks is acceptable because the applicant's proposed method of liquid waste processing by the use of demineralizers should be sufficient to process wastes generated St. Lucie 2 SSER 3 11-1

during the first fuel cycle. Therefore, the staff finds completion of the installation by first refueling acceptable.

11.5 Process and Effluent Radiological Monitoring and Sampling Systems In a letter dated October 8, 1982, the applicant identified a second continuous oxygen analyzer will not be completed by core load. The reason provided by the applicant is that this item was a recent engineering change which has not allowed sufficient time to fully incorporate the item into a reasonable con-struction schedule. The applicant further states that this fact combined with the heavy demand on both the mechanical and electrical trades precludes comple-tion by core load and completion date*is now scheduled for first refueling.

The staff accepts the FP&L proposal to complete the installation of the second continuous analyzer by the first refueling outage provided that gaseous waste collection header samples are obtained and analyzed by the laboratory gas analyzer for oxygen at least once per*24 hours when the existing oxygen analyzer becomes inoperable. This interim requirement will be specified in the St.

Lucie, Unit 2 Radiological Effluent Technical Specifications. We judge that this is acceptable for the first year of_'operation.

Also in the applicant's submittal of October 8, 1982; FP&L proposed that the electrical connection of the atmospheric steam dump and plant vent high range radiation monitors be delayed from prior .to core load to prior to exceeding 5%

power due to recent engineering changes, a short procurement interval, and a fhortage of critical electrical trades at St. Lucie 2.

We accept the FP&L proposal to *complete the installation of atmospheric steam dump exhaust and plant vent stack high range monitors prior to exceeding 5%

power level. We agree with FP&L that no appreciable amounts of fission products are generated at less than 5% power level, so requiring high range monitors is not warranted prior to 5% power. This item is included under operational requirements of the Technical Specifications which is Appendix A of the operating license.

• St. Lucie 2 SSER 3 11-2

13 CONDUCT OF OPERATIONS

.13.3 Emergency Planning 13.3.2 Evaluation of the Emergency Plan 13.3.2.8 Emergency Facilitie~ and Equipment In SER Supplement 2, Section 13.3.2.8, dated September 1982, the staff reported that the conceptual design of th~ final Emergency.Response Facilities (ERFs) was under review and that an evaluation of these facilities would be provided at a later date. Supplement 1 to NUREG-0737, Requirements For Emergency Response Capability (Generic Letter No. 82-33), issued on December 17, 1982, states that the NRC will not conduct pre-implementation reviews of ERFs. Supplement 1 to NUREG-0737 proiides all licensees and applicants with the requirements and guid-ance against which the ERFs will be evaluated in a post-implementation appraisal.

Generic Letter No. 82-33 requests that each licensee and applicant develop and submit to the NRC (by April 15, 1983) its own plant~specific .schedule for completion of the ERFs, including a description of the plans for phased imple-mentation and integration of the emergency response activities .. Accordingly,.

the schedule for the post-implementation appraisal of the St. Lucie plant ERFs will be established after these facilities have been completed.

13.3.3 Review and Evaluation of State and Local Plans by the Federal Emergency Management Agency (FEMA)

Subsequent to the issuance of St. Lucie Unit 2 SSER No. 2 (NUREG-0843, September 1982), FEMA provided the staff with supplemental information regard-ing the status of offsite emergency planning and preparedness. Under corre-spondence dated November 1, 1982, FEMA identified one major deficiency involv-ing public education and information. This matter was reviewed by the Regional Assistance Committee on January 12, 1983, and was observed by FEMA during the emergency exercise held at.St. Lucie on January 20, 1983. FEMA 1 s formal critique of the exercise has not yet been submitted to the NRC; however, initial reports from FEMA Region IV and NRC Region II concerning the public education and infor-mation program indicate that this matter has been satisfactorily corrected.

Under correspondence dated February 7, 1983, FEMA Region IV states that State and local plans conform to FEMA guidance with regard to public education 1and information. Further, the revised Florida Radiological Emergency Plan for Nuclear Power Facilities is adequate to protect the health and safety of the public in the area of the St. Lucie plant. Refer to Appendix I for the FEMA correspondence submitting the status reports.

13.3.5 Conclusions Based on the review of the applicant's plan and the review of the FEMA evalua-tion of State and local plans, the staff concludes that the state of onsite and offsite emergency preparedness provides reasonable assurance that adequate pro-tective measures can and will be taken in the event of a radiological emergency.

St. Lucie 2 SSER 3 13-1

13.6 Physical Security Plan By letters L-83-215 dated April 5, 1983 and L-83-217 dated April 6, 1983, Florida Power & Light Company has agreed to upgrade certain areas from DFO (desired for operation) to vital areas. These changes will be implemented for St. Lucie No. 2 prior to initial criticality, and this will be a condition of the license. Based upon the subject letters, the staff has re-reviewed the plan regarding vital areas for the purpose of physical protection and has determined that certain additional areas and items of equipment described in the subject letters should be included. Furthermore, prior to initial criticality, the licensees will be required to perform a reevaluation of vital areas with due regard to the safety-safeguards interface and provide the NRC the results of their reevaluation. Accordingly, the protection provided will ensure that the health and safety of the public will not be endangered.

St. Lucie 2 SSER 3 13-2

14 INITIAL TEST PROGRAM The testing activities to be performed on safety-related systems at the St. Lucie Plant Unit No. 2 are divided into two major phases: preoperational testing and.startup testing. The preoperational testing phase is comprised of generic prerequisite tests, system preoperational tests an~ integrated system

• functional tests. The sum of .these tests prepares the plant for fuel loading and subsequent startup testing. Startup testing consists of initial fuel loading, cold precritical testing, post-fuel loading hot functional testing, initial criticality, low.power physics testing, and power ascension testin~.

As part of the initial FSAR Chapter 14 review, item 640.7 requested that the applicant state which portions of any preoperational tests would be delayed until after fuel loading and to provide technical justification for each delay.

The applicant responded that certain portions of the following tests would be delayed until after fuel loading:

• Subsection Test 14.2.12.1.lOR Miscellaneous Lifting Equipment Test 14.2.12.1.lON Piping Vibration Test 14.2.12.1.71 Feedwater Regulating Test The technical justifications for delaying portions of these tests were reviewed and were found acceptable, as reported in NUREG-0843, Safety Evaluation Report for St. Lucie Plant Unit No. 2, Section 14.

Subsequent to issuance of the SER, the applicant stated in two letters from Robert Uhrig to Darrell Eisenhut dated March 25, 1983 (FPL Ref. Ltr.

No. L-83-183) and March 31, 1983 (FPL Ref. Ltr. No. L-83-192) that certain portions of the following tests, in addition to those contained in the response to item 640.7, may be delayed past fuel loading:

Subsection Test 14.2.12.1.31 Hydrogen Recombiners 14.2.12.1.3J Hydrogen Samplers 14.2.12.1.3M Safeguard and Reactor Cavity Sump Pumps 14.2.12.1.3N In-Place Testing of HEPA and Charcoal Filters 14.2.12.1.7B Loose Parts Monitoring 14.2.12.1.7F Reactor Cavity Sump Leak Detector 14.2.12.1.71 Incore Instrumentation 14.2.12.1.SA Liquid Waste.Management 14.2.12.1.8D Waste Compactor and Drumming Station 14.2.12.1.lOC Circulating Water 14.2.12.1.lOJ Secondary Sampling 14.2.12.1.lOL Radiation Monitoring 14.2.12.1.lOM Area Monitors 14.2.12.1.100 Boric Acid Concentrators 14.2.12.1.lOP Boric Acid Heat Tracing St. Lucie 2 SSER 3 14-1

Subsection Test 14.2.12.1.lOQ Boric Acid Recovery 14.2.12.1.lOR Miscellaneous Lifting Equipment 14.2.12.1.llC Fuel Handling Building Ventilation 14.2.12.1.llF Auxiliary Building Ventilation 14.2.12.1.llF RAB Leak Test 14.2.12.1.llG Shield Building Ventilation 14.2.12.1.lSH Essential Lighting The Procedures and Systems Review Branch, other appropriate Branches (CSB, RSB, METB, ASB, CPB, CHEB and LGB), Region II representatives, and contractor personnel from Battelle Pacific Northwest Laboratories (PNL) have reviewed the technical justification for delaying the portions of these tests described in the referenced letters. Based on the*stiff review using the review criteria provided in NUREG-0800 (U. S. NRC Standard Review Plan Section 14.2, Initial Plant Test Program) and by comparison with the St. Lucie Unit No. 2 Technical Specifications, the staff finds FPL's proposed delays acceptable.

We conclude that changes to the scheduling of these tests are consistent with the safety analysis previously performed, and that the conclusions previously reached in the SER are still valid. Specifically, the systems required to prevent, limit, or mitigate the *consequences of postulated accidents will still be tested prior to exceeding 25% of rated power, and the safety of the plant will not be dependent on the performance of untested systems, structures, and components. We have also concluded that the initial test program description still meets the test requirements of General Design Criterion 1 of 10 CFR 50 Appendix A, the acceptance criteria of Section 14.2 of the Standard Review Plan, and Section XI of 10 CFR 50 Appendix B, and therefore is acceptable.

St. Lucie 2 SSER 3 14-2

15 ACCIDENT ANALYSIS 15.6 Reactivity and Power *oistribution Anomalies 15.6.3 Inadvertent Boron Dilution In Section 15.6.3 of our Safety Evaluation Report of October 1981, we stated that the applicant has modified the St. Lucie 2 FSAR to commit to the installa-tion of startup channel flux alarms, which will be utilized to detect the occurrence of a boron dilution event in modes 3 through 6. There will be two separate alarms, both capable of being powered from separate onsite power sources.

In letter dated November 4, 1982, the applicant stated that the boron dilution alarm system cannot be installed until late in 1983. FPL will implement proce-dures for detection of boron dilution until the boron dilution alarms are installed.

The applicant proposed interim operating procedures and Technical Specifications detection of an inadvertent boron dilution including the following: (1) The operator shall observe the count rate indicated by the source range flux channels when entering modes 3, 4, or 5. From that time, the flux count rate shall be observed at the applicable monitoring frequency for the duration of plant operation; (2) the operator shall determine the RCS boron concentration when entering modes 3, 4, or 5. From that time the RCS boron concentration shall be determined at the applicable monitoring frequency for the duration of plant operation. The boron concentration shall be determined by either monitor-ing the boronmeter control room readout or performing an RCS boron concentra-tion sample analysis; (3) If the RCS is drained significantly in mode 5, only one charging pump shall be allowed in operation; and (4) in mode 6, the manual isolation valves in the reactor makeup water line should remain locked closed at all times.

We have reviewed the applicant's proposed interim procedure guidelines for detection of boron dilution event and the associated mode d~pendent times between initiation of a postulated dilution event and criticality. The applicant's analyses have assumed conservative rod configurations (all rods out) and the associated times are acceptable. The St. Lucie Unit 2 Technical Specification will include the above required monitoring procedure and a table specifying the monitoring frequencies for boron dilution detection at various operating mode to ensure proper system monitoring during time when changes in RCS temperature may mask changes in core flux (due to a postulated boron dilution event), the applicant has inlcuded Technical Specifications that require increased monitoring during RCS cooldowns. We have reviewed the applicant's procedures, analyses, and technical specifications and find them acceptable.

St. Lucie 2 SSER 3 15-1

15.10 Limiting Accidents 15.10.2 Feedwater System Pipe Breaks Section 15.10.2 of the St. Lucie 2 SER reported the need for additional information and analyses for the purpose of demonstrating compliance to SRP Section 15.2.8. Specifically, since-the applicant's analyses resulted in RCS pressure above 110% of the design pressure, the SER required the applicant to address the following concerns:

(1) Consequence of the limiting sin~le failure, such as a failure of the MSIV to close at the limiting time, or events which could result in the pressurizer filling solid, and (2) Consequence of the time to MS1v*c1osure (i.e., closure resulting from a high containment pressure signal). -

In addition to the r*equi rements listed above, the SER stated that the review of the acceptability of exceeding 110% of the primary system design pressure for postulated small feedwater line breaks was ongoing. In a letter dated October 5, 1982 from Kerrigan (NRC) to Uhrig (FPL),* 11 st Lucie-2 FSAR Request for Additional Information," the applicant was requir:d to demonstrate that small feedwater line breaks will not result in exceeding 110% of the primary system design pressure. This analysis is required to show adequate safety margins for postulated small feedline breaks. Also, the analysis is required to show an acceptable level of understanding of plant and systems responses to postulated small feedline break accidents.

Amendments 7 and 11 to the applicant's FSAR were submitted in response to the concerns outlined above. Amendment 7 documents that no single failure exists which could result in a more severe overpressurization than already analyzed.

This conclusion was derived from the applicant's conservative analytical assump-tion of rapid heat transfer degradation and crediting reactor trip only from a high pressurizer pressure signal (no credit for steam generator low-level trip). Postulating additional failures would lead to a reactor trip prior to heat transfer degradation. This, in turn, would result in a less severe pres-surization as a result of both steam generator availability to remove decay heat. The staff finds the licensee's response to confirmatory items 1 and 2, as listed above, acceptable.

The applicant's response to concerns relating to small feedwater line breaks providing system pressures which exceed 110% of the primary system design pres-sure is documented in Amendment 11 to the FSAR. The applicant defined small breaks as less than 4 inches in equivalent diameter. The staff does not concur that a noticeable decrease in probability of occurrence exists between a 4- and a 6-inch equivalent break diameter. Since the limiting pressurization transient was calculated to occur for an approximate 6-inch diameter break, the staff does not concur that the difference in failure probability warrants exceeding 110% of the primary system design pressure. The applicant agreed to reevaluate the limiting small feedwater line break event and demonstrate that the resulting consequences wi 11 not exceed 110% of .. the primary system design pressure.

St. Lucie 2 SSER 3 15-2

In a letter dated December 9, 1982 from R. E. Uhrig (FPL) to D. Eisenhut (NRC),

"Small Feedwater Line Break Analysis," the.applicant submitted reanalyses of the FSAR small feedwater line break events. The new analyses demonstrated that the peak primary system pressure would not exceed 110% of design, as required by Section 15.2.8 of the Standard Review Plan. This was achieved by modifying the methodology for evaluating small feedwater line breaks, and thereby reducing the resulting peak primary system pressure from 2750 psia to 2621 psia.

The modification to the feedwater line break methodology consisted of crediting steam generator low level trip~ The previous methodology did not credit low level trip and therefore resulted in exceeding 110% (2750 psia) of the primary system design pressure. The previous methodology*was developed to bound the uncertainties of time to low level trip for postulated large feedwater line breaks, where the potential for frothing of coolant inventory within the steam generator downcomer introduced large uncertainties into the calculation. Consequently, low level trip was not credited until all liquid inventory in*the secondary side of the broken steam gener 9tor was depleted.

During a small feedwater line break event, large uncertainties in the secondary side level due to frothing are not anticipated, since the affected generator does not undergo a severe depressurization. The applicant modified the analytical methodology by conservatively delaying the time to low level trip until the secondary liquid inventory decreased to 21,000 lbm. Low level

• trip for this event is anticipated to occur at a liquid inventory in excess of 70,000 lbm. The staff finds this modified methodology for crediting low level trip for sma 11 f eedwater line breaks acceptable.

• In addition to crediting low level trip, the applicant modified the methodology of calculating primary to secondary heat transfer. The peak primary pressure is governed by the rate of loss of heat transfer. During a slow rate of heat transfer degradation, secondary inventory will be relatively high at the time of reactor trip. With the presence of secondary inventory, heat transfer for decay heat removal would continue. This limits the severity of the pressuriza-tion. A rapid heat transfer degradation rate, on the other hand, maximizes the imbalance of core heat generation relative to steam generator heat extraction.

This phenomenon 1eads to higher predicted primary* system pre*ssures. Previous applicant analyses conservatively assumed a step loss in the heat transfer coefficient between the primary and s~condary systems. The new methodology was modified to simulate heat transfer degradation as a function of secondary system inventory. This degradation was initiated at an -inventory of 21,000 lbm, the condition at which the local void fraction near the top of the steam generator tubes increased*to 98% (this corresponds to a local flow quality of 0.9, as calculated by CESEC). The secondary side inventory, corresponding to 90% flow quality at the top of the tube bundle, was derived from the CESEC-ATWS computer program. This program was previously approved for evaluating ATWS pressuriza-tion events.

The applicant stated that the new methodology for modeling steam generator heat transfer degradation is conservative. This is attributed to neglecting transi-tion boiling. The applicant stated that heat transfer degradation is expected to occur at the time when liquid inventory within the broken steam generator is still in excess of 70,000 lbm. This would produce a slow rate of heat transfer degradation and result in a less severe overpressurization event. The degree of St. Lucie 2 SSER 3 15-3

conservatism resulting from the applicant's new methodology for analyzing small feedwater line breaks has not been quantified.* However, the staff has reasonable assurance that the peak primary system pressure for a small feedwater line break would not exceed 110% of the primary system pressure. This conclusion is based on generic audit calculations performed by Argonne National Laboratory, under con-tract to the NRC. The NRC is initiating a joint program with Westinghouse and EPRI to obtain experimental steam generator heat transfer data which we believe can be used.for quantifying the conservatisms in the applicant's feedwater line break methodology. Based upon independent analyses and our understanding of the conservative assumptions utilized by the applicant, we have reasonable assurance at this time that our conclusions will not be appreciably changed by completion of the small feedwater line break methodology review. The methodology utilized for large feedwater line breaks, as documented in greater detail in Appendix l5B of the CESSAR FSAR, is acceptable. **

Should our review indicate that revision to the analyses are necessary, the applicant will be required to revise the small feedwater line break analyses as appropriate.

• The staff concludes that the consequences of postulated feedwater line breaks meet the requirements set forth in the General Design Criteria 27, 28, 31, and 35 regarding control rod insertability and primary system integrity.

15.10.4 Steam Generator Tube Rupture In Section 15.10.4 of the SER, we indicated that the staff requires the applicant to perform a reanalysis of the steam generator tube rupture (SGTR) event using the CESEC-III computer code. In response to the staff request, the applicant, in Amendment 7 to St. Lucie 2 FSAR, provided the results of this reanalysis.

The steam generator tube rupture (SGTR) accident is a penetration of the bar-rier*between the reactor coolant system (RCS) and the main steam system and results from the failure of a steam generator U-tube. Integrity of the barrier between the RCS and main steam system is significant from a radiological re-lease standpoint. The radioactivity from the leaking steam generator tube mixes with the shell-side water in the affected steam generator. Prior to turbine trip, the radioactivity is transported through the turbine to the con-denser where the noncondensible radioactive materials would be released via the condenser air ejectors. Following reactor trip and turbine trip, with the steam bypass system in its manual mode, the steam generator safety valves open to contrql the main steam system pressure. The operator can isolate the damaged steam generator any time after reactor trip occurs. The cooldown of the nuclear steam supply system can then be performed by manual operation of the emergency feedwater and the steam bypass control system (SBCS), and using the unaffected steam generator. The analysis presented conservatively assumes that operator action is delayed until 30 minutes after the initiation of the event.

Th~ radiological consequences for the SGTR transient, which are evaluated in Section 15.11.4 of the SER 1 are also dependent on the break size. For break sizes resulting in a reactor trip during the first 30 minutes of the accident, the initial leak rate decreases from that value equivalent to a double-ended St. Lucie 2 SSER 3 15-4

rupture, and the offsite dose also decreases due to the drop in the integrated leak. The decrease in break size also delays the time of reactor trip. As the break size is decreased further, the integral leak is reduced for the 30-minute operator*action interval and the radiological consequences will be less severe. Therefore, the most adverse break size is the largest assumed break of a full double-ended rupture of a steam g~nerator tube.

The CESEC-III computer program was used to simulate the SGTR event. CESEC-III accounts for void formation in the primary.system once the pressurizer empties.

The SGTR event is the most limiting event with respect to void formation.

Voids form in the vessel upper head region during the accident, due to the thermal hydraulic decoupling of this region from the rest of the RCS following reactor coolant pump trip. The upper head region liquid level remains well above the top of the hot leg throughout the transient. Furthermore, the upper head voids begin to collapse upon actuation of the safety injection flow.

After 30 minutes, the operator employs the plant emergency procedure for the steam generator tube rupture event to cooldown the plant to shutdown cooling entry conditions.

The SGTR event was analyzed both with and without a concurrent loss of offsite power (LOP) at the time of reactor trip. A technical specification limit of 1 gpm leakage in the unaffected steam generator was assumed for the duration of the transient. *

• The maximum RCS and secondary pressures do not exceed 110% of design pressure following a steam generator tube rupture event both with and without a con-

• current loss of offsite power, thus assuring the integrity of the RCS and the main steam system. The minimum DNBR of 1.39 is above the minimum ONBR limit of 1.19 and, therefore, no fuel. failure is assumed to occur.

The plant is maintained in a stable condition due to automatic actions, and after 30 minutes, the operator employs the plant emergency procedure for the steam generator tube rupture event to cooldown the plant to shutdown cooling entry conditions.*

The staff finds the assumptions used and the analyses performed for this event to be acceptable and that the scenarios, as described by the applicant, assure that the most severe SGTR event has been considered.

• 15.10.5 Inadvertent OpenJng of a Pressurizer Relief Valve In Section 15.10.5 of the SER, we stated that the staff required the applicant to include.the CESEC analysis for the inadvertent opening of a pressurizer relief valve in the FSAR, when the analysis is completed. FP&L agreed with this requirement. The staff further required the applicant to provide an estimate of the number of fuel failures and to provide the radiological dose calculation for this event, with a single active component failure, in accord-ance with the requirements of Standard Review Plan Section 15.6.1.

In Amendment 11 to the FSAR, the applicant has provided the results of the subject analysis.

St. Lucie 2 SSER 3 15-5

The inadvertent opening of a power-operated relief valve (PORV) was analyzed to demonstrate that this event does not result in violation of the specified acceptable fuel design limits.(SAFDL). The event was analyzed both with and without a loss of offsite power following turbine trip. The limiting case was determined to be a loss of offsite power. Based on the recommendation in

'ANS 58.8, ANSI 660 Rev. 2, 11 Time Response Design Criteria for Safety Related Operator Action," March 1981, the operator was assumed to have identified the event and close the PORV at ten minutes.

The CESEC-III computer program was used to simulate this event. CESEC-III accounts for void formation in the primary system if the pressurizer empties.

The maximum RCS and secondary pressures do not exceed 110% of design pressure following the inadvertent opening of a PORV, thus assuring the integrity of the RCS and the main steam system. The minimum DNBR of 1.23 is above the minimum DNBR limit of 1.19 and, therefore. no fuel failure is assumed to occur.

The plant is maintained in a stable condition due to automatic actions,* and after 30 minutes, the operator opens the atmospheric dump valves (ADVs) and controls the dumping of steam to the atmosphere until shutdown cooling entry conditions are reached.

The staff finds the assumptions used and the analyses performed for this event to be acceptable and that the scenarios, as described by the licensee, assure that the most severe inadvertent opening of a PORV event has been considered.

15.11 Radiological Consequences of Design Basis Accidents 15.11.5 Loss-of-Coolant Accident (Radiological Considerations)

The operating licenses for nuclear power plants contain'technical specifications prescribing limits to be confirmed by periodic tests of the iodine retention efficiency of charcoal filtration units and measurements of leakage through specified containment penetrations. The computed dose consequences in the SER assume efficiencies and leakages directly related to the proposed license tech-nical specifications. Discussions between the staff and the applicant have led to the conclusion that the charcoal filtration units built at St. Lucie Unit 2 are unlikely to be successfully maintained at the high iodine retention efficien-cies assumed for them in the SER. Consequently, less reliance should be placed upon the abilities of those filters, and correspondingly greater emphasis should be placed upon the maintenance and capabilities of other plant safety features.

Table 15.l contains revised computed doses resulting from this change in assumed iodine retention abilities, while Table 15.2 contains the current assumptions.

Since these changes do not affect*the computed retention of fission products other than iodine, all computed doses reported in the SER other than thyroid inhalation doses remain the same.

The chief reduction in assumed charcoal filtration capability affects the fil-tered exhaust of the emergency core cooling system pump rooms. These filters are now assumed to be incapable of operating should a pump seal totally fail, releasing steam into the filtered exhaust. The staff has, following Sec-tion 15.6.5, Appendix B of the Standard Review Plan, assumed such a failure.

St. Lucie 2 SSER 3 15-6

The applicant has proposed two significant measures to improve control of accidental iodine releases. The first is to reduce bypass of the secondary containment form 27% to 12% of total containment leakage. The second is to modify the containment spray additive system and its mode of emergency operation.

By this modification, hydrazine can be maintained in the containment spray and sump solutions for an additional ten hours beyond that assumed originally.

These two modifications are approximately equivalent to the thyroid .dose miti-gation capabilities contained in the charcoal filter efficiency reduction, and result in approximately the same 30-day dose consequences. There is also, how-ever, a significant reduction in the computed 2-hour thyroid dose at the exclu-sion area boundary. Since this modification requires a manual operator action outside the control room, the incremental operator dose was evaluated and is reported in Section 6.4 The computed accident doses are either less than or approximately equal to those previously reported in the SER. The revised dose calculations have been performed consistent with the applicable sections of NUREG-0800 and Regulatory Guides. The doses computed for this accident are less than the guideline values of 10 CFR 100.11 and the staff concludes that St. Lucie Unit 2 is adequately designed to mitigate the offsite consequences.

St. Lucie 2 SSER 3

• 15-7

Table 15.1 Revised loss-of-coolant dose consequences Thyroid dose (rem) Whole body dose (rem)

Exclusion Area Boundary 0-2 hours 71. 3.0 Low Population Zone 0-2 hours 30 1.3 2-8 hours 31 1. 9 8-24 hours 45 0.8 1-4 days 146 0.2 4-30 days 32 0.1 Total 284. 4.3 Table 15.2 Revised loss-of-coolant dose assumptions Passive failure of ECCS time of failure, hours 24 coolant leak rate, gpm 50 duration of leak, min 30 Containment leak fraction bypassing filtration,% 12

• Duration of containment spray additive, hours 12 Iodine filtration efficiencies of containment leakage treatment elemental 95 organic 50 particulate 99 St. Lucie 2 SSER 3 15-8

22 TMI-2 REQUIREMENTS 22.2 Discussion of Requirements I.D.1 Control Room Design Review Position Human factors engineering in nuclear power plants is addressed by Chapter 18 of the NRC's Standard Review Plan (NUREG-0800, July 1981). The preliminary control room design review at St. Lucie Plant, Unit No. 2, was consistent with Sections 18.4 and 18.5 of that chapter. The Section 18.5 review was lim,ted to the remote shutdown panel. The following is a summary of the results or the preliminary contr~l room design review since publication of Supplement No. 1 to the SER.

Discussion The applicant's preliminary design assessment (PDA), submitted July 6, 1981, and the staff's onsite control room design review/audit (CRDR/A), conducted August 3-7, 1981, identified 169 human engineering discrepancies (HEDs) in the St. Lucie Plant, Unit No. 2 control room. SER Supplement No. I listed 127 of those HEDs which required prelicensing correction. The staff agreed that the remaining 42 HEDs may be specifically addressed as part of the detailed control room design review (DCRDR). The applicant's acceptable commitments and imple-mentation schedules for HEDs requiring prelicensing correction were also listed in SER Supplement No. 1. Acceptable modifications to those commitments were submitted by the applicant in a letter from R. E. Uhrig to F. J. Miraglia (dated October 29, 1982) and in two letters from R. E. Uhrig to D. G. Eisenhut (dated November 10, 1982 and January 14, 1983 respectively).

Eight systems or items, identified in SER Supplement No. 1 were not reviewed

• in the applicant's PDA or the staff's CRDR/A. The applicant was required.to evaluate those systems or items and, 60 days prior to issuance of an operating license, to submit an evaluation report for NRC approval. Detailed findings, proposed corrective actions, and implementation schedules were to be included in the applicant's evaluation report. The required report was submitted with the applicant's October 29, 1982 letter from R. E. Uhrig to F. J. Miraglia.

Supplements to the report were submitted with the applicant's November 10, 1982 and January 14, 19~3 letters from R. E. Uhrig to D. G. Eisenhut.

The NRC Resident Inspector is conducting a post-implementation audit to ~omplete the prelicensing control room design review. The audit specifically addresses HEDs for which prelicensing correction (per SER Supplement No. 1) is required.

Completion of approximately 90 percent of the corrections to HEDs had been confirmed by March 30, 1983.

In a February 14, 1983 letter from R. E. Uhrig to D. G. Eisenhut, the applicant indicated that commitments to correct two HEDs (Findings A.8.7 and A.8.9 in SER St. Lucie 2 SSER 3 22-1

Supplement No. 1) could.not be satisfied without delaying power ascension by about 10 days. The two items.dealt with left-to-right and top-to-bottom reversals of instrumentation and controls on the safeguards panel (RGB 206).

The probability of human errors associated with such reversals is higher than with properly arranged instrumentation and controls. The staff indicated concern with the delay because the reversals involved instrumentation and controls associated with (1) Safety.Injection Tanks 2Al and 2A2; (2) Low Pres-sure Safety Injection to. cold legs-2Al and 2A2; and (3) High Pressure Safety Injection to cold legs 2Al and 2A2 .. A March 11, 1983 letter from R. E. Uhrig to D. G. Eisenhut provided the applicant's analysis of the consequences of not correcting Findings A.8.7 and A.8.9 prior to licensing. That letter indicated that the systems in question are either passive or are activated automatically on a safety injection signal. No operator action is required to satisfy the conditions of the safety analysis for either large or small break LOCAs. The applicant's March 11, 1983 letter also indicated that, under some conditions, the operator may elect to take action following automatic initiation of HPSI

• and/or LPSI. "Given that the operator decides to take action, an error (due to improperly arranged instrumentation and controls) which woulp affect HPSI or LPSI flow and which remained uncorrected for more than one minute would exceed the conditions for the safety analyses for large and small break LOCAs. A March 30, 1983 letter from R. E. Uhrig to D. G. Eisenhut indicated that such operator errors could be corrected within one minute based on a task analysis the applicant provided earlier.

It is the staff's judgment that the likelihood of the combination of (1) an accide~t requiring HPSI and/or LPSI; (2) failure of automatic safety injection; (3) operator action which adversely affects HPSI or LPSI, and (4) failure to correct that error within a minute is sufficiently small to allow delaying cor-rection to Findings A.8.7 and ~.8.9. However, it is the staff's view that the.

issues raised in Findings A.8.7 and A.8.9 remain of sufficient concern to war-

-rant correction by startup following the first refueling outage. The applicant has.committed to correct Findings A.8.7 and A.8.9 prior to startup after the first refueling outage in a March 30, 1983 letter from R. E. Uhrig to D. G.

Eisenhut. All other prelicensing commitments for HED corrections which cannot be implemented by the licensing date must be completed prior to St. Lucie Plant, Unit No. 2 going above 5% power.

The post-implementation audit is also addressing human factors engineering of the eight systems or items which were to be evaluated by the applicant follow-ing the CRDR/A. The applicant's environmental surveys indicate that prelicens-ing requirements for one of those items, control room and remote shutdown panel environment, are satisfied. The applicant's evaluation of another item, plant process computers, identified a number of HEDs. Acceptable commitments for correction of several of those HEDs were made. Those corrections should be completed prior to St. Lucie Plant, Unit No. 2 going above 5 percent power.

The applicant's commitments with respect to other plant process computer HEDs indicated the need for continued evaluation during the DCRDR. The remaining plant process computer HEDs must be specifically addressed as part of the DCRDR.

The applicant indicated that human factors engineering was considered during the design of the following systems or items: (1) control room layout, (2) operator's console, (3) communications system, (4) controls and displays added since the CRDR/A, (5) auditory signal system, and (6) emergency equipment storage. The above systems or items will be completed in the control room St. Lucie 2 SSER 3 22-2

prior to exceeding 5% power. Evaluation of these systems or items in the control room will be required as part of the DCRDR.

Conclusion The applicant and staff have reached technical agreement on those control room design review items which are required, per SER Supplement No. 1, to be com-pleted prior to licensing. However, only about 90 percent of the prelicensing corrections of HEDs were found to be acceptably completed by March 30, 1983.

Although most items are currently scheduled to be completed prior to licensing,.

the applicant has indicated that corrections for two HEDs (Findings A.8.7 and A.8.9 in SER Supplement No. 1) cannot be*completed by that time without affect-ing the schedule for ascension to power operation. This delay is acceptable; however, the license will be conditioned.to require correction of Findings A.8.7 and A.8.9 prior to startup after the first refueling outage. Several other prelicensing control room commitments are not expected to be completed prior to issuance of a license. These delays ar~ also acceptable; howe~er, the license will be conditioned to require completio~ of those prelicensing control room requirements before St. Lucie, Unit No. 2 goes above 5% power. The staff has concluded that these delays will riot result in increased risk to public*health and safety.

Satisfaction of all prelicensing requirements will complete the preliminary control room design review of St. Lucie Plant, Unit No. 2. The plant must still be subjected to a DCRDR. Requirements for the DCRDR are identified in Supplement 1 to NUREG-0737, "Requirements for Emergency Response Capability" (Generic Letter No. 82-33). The DCRDR for St. Lucie Plant, Unit No. 2 must, in addition, address all issues which the staff agreed could be postponed until that review. Completion of prelicensing control room commitments and the DCRDR will be reported in subsequent SER supplements.

I.D.2 Plant Safety Parameter Display Console Supplement 1 to NUREG-0737, "Requirements for Emergency Response Capability" (Generic Letter No. 82-33), was issued on December 17, 1982. Part of the pur-pose of Gener~c Letter No. 82-33 is to provide additional clarification of the requirements regarding Safety Parameter Display Systems (SPDS) and the letter requests each applicant to develop and submit to the NRC (by April 15, 1983) its own plant-specific implementation schedule. Accordingly the implementation

• schedule for the SPDS will be addressed in the broader context of the require-ments for.emergency response capability for St. Lucie 2 .. This will include the schedules for the Control Room Design Review, upgraded Emergency Operating Pro~dures, Technical Support Center, Operational Support Centei, Emergency Response Facility and R.G. 1.97, Revision 2. Therefore, at this time the license will not be conditioned as indicated in Section 1.9 of Supplement 1 to the SER.

II.8.2 Design Review of Plant Shielding and Vital Area Access The applicant has.proposed construction delays as follows for systems related to NUREG-0737, Item II.8.2, plant shielding and vital area access:

St. Lucie -2 SSER 3 22-3

a) Motor operated valves (V-3432, V-3444, I-MV-07-03, I-MV-07-04) - delay electrical hookups until 8 months after core load due to demands on electrical construction trades.

b) ECCS Area Sump Pumpback System - delay electrical hookups to motor operated valves prior to exceeding 5% power, due to critical demands on electrical construction trades.~

c) Post Accident Sampling System - potential delay in system construction and electrical hookup (initial applicant proposal was to make complete and operational prior to exceeding 5% power) due to recent delivery of hardware, realignment or priorities, and critical demands on electrical construction trades. A subsequent applicant submittal showed improvement in the completion schedule by initial critiality. If the system is not operational by initial criticality, the applicant has committed to interim compensating measures.

The applicant has stated that the motor operated valves identified in (a) above are not required to be activated for safe shutdown or accident mitigation, and the ECCS Area Sump Pumpback system motor operated valves identified in (b) above are isolated by containment isolation. Since these areas and systems which .are affected by the construction delays are not identified as vital areas, they are not required to meet the criteria for shielding and access of NUREG-0737, Item II.B.2.

A delay in completion of the postaccident sampling system identified in (c) above until prior to exceeding 5% power, affects a vital area identified in respons*e to NUREG-0737, Item II.B.2 in the St. Lucie FSAR. As noted above, th~ applicant has committed to completion of the sampling system prior to criticality.

We find that the applicant has provided reasonable compensating safety actions for the delay in completion of the postaccident sampling system if it is not operational by initial criticality.

Item II.B.3 Post Accident Sampling I. Introduction According to NUREG 0737, the installation of a post accident sampling system (PASS) is to be completed prior to core load for NTOL's which are completed after January 1, 1982. By letter dated May 4, 1982, the applicant requested to extend this date to 12 months after core load (December 1983). The appli-cant proposed to use the normal sampling system in the interim until the PASS was completed. This would have permitted full power operation without a fully operational post accident sampling capability. In SSER 2 (NUREG 0843 dated Sept. 1982), we concluded that the applicant had not provided sufficient justi-fication to demonstrate that the normal samplinE system, which was proposed to be utilized in lieu of the PASSi would meet the PASS requirements of NUREG 0737 and therefore, the schedule delay was found unacceptable. The applicant revised the PASS schedule in a letter d~t~d October 8, 1982 and proposed to complete the PASS prior to exceeding 5% power. Subsequently, by letter dated December 9, 1982, the applicant agreed to change the completion date for.the PASS to prior to initial criticality.

St. Lucie 2 SSER 3 22-4

As identified in SSER 2 (Supplement No. 2 to NUREG 0843) the PASS items that remained unresolved were as follows:

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

2. Provide the capability to identify and quantify the activity for reactor coolant and containment atmosphere post accident samples.

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

Furthermore, the applicant was required.to submit data supporting the applicabil-ity of each selected analytical chemistty procedure or online instrument along with documentation demonstrating compliance prior to exceeding 5% power opera-tion, but the review and approval of these procedures would not be a condition for full power operation.

II. Evaluation By letters dated December 29, 1982 and March 4, 1983, the applicant has provided additional information.

1. Reactor coolant chloride analysis can be obtained within the required four day period. Initial analysis of a diluted grab sample for chloride concentration utilizes the mercuric nitrate manual titration. Collection of an undiluted*grab sample in a ihielded cask will be retained for analy-sis within 30 days consistent with ALARA. We find that these provisions meet the PASS criterion and are, therefore, acceptable.

2. The PASS radiological and chemical sample analysis capability includes provisions to identify and quantify the radioisotopes of concern corresponding to the source terms given in Regulatory Guide 1.4 and 1.7.

The PASS sampling system instrumentation is designed to cover adequate ranges, accuracies and sens1tivities to allow the operator to obtain pertinent data to describe*the radiological and chemical status of the reactor coolant system. We find that these provisions meet the PASS criterion and are, therefore, acceptable.

3. The interim procedure for core damage assessment utilizes only the radio-logical analysis of samples obtained from the PASS. Sample locations (RCS hot leg, RCS pressurizer, containment sump, containment atmosphere, shutdown cooling system, and steam generator secondary) that are appro-priate for core damage assessment are identified. The extent of damage is estimated by characterizing the fission products, calculating the isotopic ratios; and comparing them to estimated gas gap and pellet ratios. The degree of core damage is expressed in terms of the percent-age of the tota 1 c*ore inventory ava*il able for rel ease. This procedure is being revised to include comparisons with additional PASS data (e.g.

hydrogen concentrations and total gas content in the samples) and other instrumentation data which relates to core integrity, including RCS pres-sure, core exit thermocouple temperatures, and containment radiation levels.

We find that these provisions partially meet the PASS criteria.

St. Lucie 2 SSER 3 22-5

The applicant's letter of December 29, 1982, transmitted a 11 PROPRIETARY 11 report titled, 11 Engineering Evaluation and Functional Testing for the CE PASS Components and Instrum~ntation, dated November, 1982. We find this report provides verification of the applicant's PASS under the anticipated chemistry and radiation environment and meets the PASS criterion.

III. Conclusion On the basis of the above evaluation,:we have determined that except for the core damage procedure the applicant me*ets the remaining unresolved require-ments of NUREG 0737,- Item II.B.3, and are therefore, acceptable. The procedure for estimation of fuel damage is acceptable on an interim basis. By the first refueling, the applicant should incorporate the above comments into the core damage procedure.

• II.D.1. Performance Testing of Pressurized Water Reactor Relief and Safety Valves In the Safety Evaluation Report, we stated that FPL was a participant in the EPRI/NSAC program to conduct performance testing of PWR relief and safety valves and associated piping and supports. However, at the time of issuance of the SER, the applicant had not provided a commitment to qualify the PORV block valves. NUREG-0737, Item II.D.1 requires that prior to fuel load, evidence of block valve qualification be provided to NRC.

In the SER, we concluded that for the relief and safety valves and associated piping and supports the applicant had committed to the requirements of this item to the extent practicable at that time; however, we indicated we required that the applicant provide a commitment to qualify the PORV block valves.

By letter of March 22, 1983 from Mr. R. Uhrig, FPL to Mr. D. Eisenhut, NRC, the applicant referenced two Combustion Engineering Topical Reports as documentation as to how the EPRI/NSAC test results are applicable to the St. Lucie 2 relief and safety valves. These reports are: CEN-227 dated December 1982 entitled, 11 Summary Report on the Operability of Pressurizer Safety Valves in C.E. Designed Plants 11 and CEN-213 dated July 1982 entitled, "Summary Report on the Operability of Power Operated Relief Valves. 11 The staff has not completed a detailed review of these reports, however, based on a preliminary review, we have found that the general approach in the reports of using the EPRI test results to demonstrate plant specific operability of the relief and safety valves is acceptable.

In the March 22, 1983 letter, the applicant also addressed relief and safety valve piping and support adequacy and PORV brock valve qualification. Based on the results of our preliminary review of this information and on our pre-liminary review of the two C.E. topical repo~ts, we have concluded that the applicant has complied with the requirements of II.D.1 to the maximum extent possible at this time. The applicant's general approach in responding to this TMI item is acceptable and should provide adequate assurance that the St.

Lucie 2 Reactor Coolant System Overpressure Protection System can perform its intended function for the period during which we complete our detailed review.

If the completion of our detailed review reveal~ that modifications or adjust-ments to safety valves, PORVs, PORV block valves or associated piping are St. Lucie 2 SSER 3 22-6

needed to assure that the Overpressure Protection System can perform its intended function, we will require that the applicant make appropriate modifications.

II.F.1(2c) In-containment High Range Radiation Monitor The applicant's submittals of May 4, 1982 and October 8, 1982, propose that the electrical connection of high range in-containment radiation monitors be delayed from prior to fuel load (as required in our positions in NUREG-0737 Item II.F.1(2c)) to prior to exceeding 5% power due to recent engineering changes, a short procurement interval, and a shortage of critical electrical trades at St. Lucie 2. The equipment and installation otherwise have been evaluated and meet our positions in NUREG-0737 as indicated in our Safety Evaluation Report. The applicant proposed the interim utilization of two safety-related gamma radiation monitors of 10 to 10 7 mr/hr range installed outside of containment to monitor potential in-containment postaccident dose rates for the worst case accident. A procedure has been developed to convert these monitor readings to in-containment radiation levels. Additionally, four other in-containment area radiation monitors will be available for correlative readings over a 10 to 107 mr/hr range. The applicant's proposal to delay com-pletion of the in-containment high range radiation monitors is acceptable pro-vided the applicant has these systems complete and operational prior to exceed-ing 5% power, and provided that procedures are developed and implemented prior to fuel loading to utilize the proposed out-of-containment monitors and other available in-containment radiation monitors to determine potential in-containment postaccident dose rates. This will be a condition of the license.

St. Lucie 2 SSER 3 22-7

APPENDIX A CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL REVIEW August 31, 1982 Letter from Ebasco providing interim report of how activities of Task Force have preserved independence of the program.

August 31, 1982 Letter from Ebasco transmitting minutes of August 26 meeting of Task Force mangers September 1, 1982 Letter from applicant transmitting Addendum to FSAR Amendment 12 September 3, 1982 Letter from Ebasco transmitting weekly status summary for August 20 - September 3, 1982 September 3, 1982 Letter from applicant transmitting information on handling of light loads September 3, 1982 Letter from applicant forwarding conclusions and commitments resulting from site audit on fire protection September 3, 1982 Letter from applicant providing clarification on emergency preparedness and planning items September 3, 1982 Letter from applicant regarding socket weld inspection program September 10, 1982 Letter to applicant concerning its construction completion date September 10, 1982 Letter from Ebasco transmitting weekly status summary for September 6 - 11, 1982 September 14, 1982 Meeting of Engineering Verification Task Managers to discuss the Engineering Verification Program (EVP) and the measures used to assure the independence of the EVP September 14, 1982 Letter from applicant regarding staffing and training of licensed operators September 17, 1982 Letter to applicant concerning administration of written and oral examinations to operators and senior operators September 17, 1982 Letter from Ebasco transmitting minutes of September 8 meeting of applicant, Combustion Engineering, and Ebasco EVP Task Force Managers St. Lucie 2 SSER 3 A-1

September 17, 1982 Letter from applicant regarding operator licensing September 20, 1982 Letter from Ebasco transmitting weekly status summary for September 13 - September 18, 1982 September 21, 1982 Letter from applicant transmitting response to base plate flexibility action items

. September 21, 1982 Letter from applicant transmitting information on control of heavy loads September 23, 1982 Meeting with applicant to disc~ss *the ventilation system charcoal adsorber efficiencies and the results of the

• analysis of .the radiological consequences of design basis accidents with the.use of these efficiencies

• September 24, 1982 Letter from Ebasco transmitting weekly summary for September 20-25, 1982 September 24, 1982 Letter from applicant forwarding responses to electrical audit findings September 24, 1982 Letter from Ebasco transmitting minutes of September 16 meeting of EVP Review Committee September 29, 1982 Letter from Ebasco transmitting minutes of September 23 meeting of applicant, Ebasco, and Combustion Engineering Task Force Managers

• September 29, 1982 Letter to applicant advising of acceptability of ASME Code Case N-316 September 29, 1982 Letter to applicant transmitting request for additional information regarding 10 CFR Part 50, Appendix R, Sections III.G and III.L September 30, 1982 Letter from applicant transmitting information concerning loose parts monitoring system training program September 30, 1982 Letter from applicant in response to Generic Letter 82-12, Nuclear Power Plant Staff Working Hours September 30, 1982 Letter from applicant transmitting Supplement No. 1 to NTOL Summary Human Engineering Report - Control Room October 1, 1982 Letter to applicant requesting additional information regarding fuels October 1, 1982 Meeting with applicant concerning construction completion date October 5, 1982 Letter from applicant transmitting responses to concerns regarding inadequate core cooling instrumentation St. Lucie 2 SSER 3 A-2

October 5, 1982* Letter to applicant requesting information on Amendment 11 of fSAR relative to Section 15.10.2 of.the Safety Evaluation Report October 6, 1982 Letter from applicant transmitting report on performance evaluation of containment sump at full scale October 6, 1982 Generic Letter 82 Technical Specifications for Fire Protection Audits October 7, 1982 Letter from applicant transmitting information on fire protection iJ October 7, 1982 Letter to applicant concerning status of control room design review and transmitting request for additional information October 8, 1982 Meeting with applicant to discuss p~ocedure for leak testing pressure isolation valves October 8, 1982 Letter from applicant forwarding list of engineering and, construction items not expected to be completed at core load, and justification for operation prior to their completion October 8, 1982 Letter from Ebasco transmitting weekly status summary for October 4-8, 1982 October 12, 1982 Generic Letter 82 Reactor Operator and Senior Reactor Operator Qualifications October 12, 1982 Meeting with applicant to discuss procedure for leak testing pressure isolation valves October 12, 1982 Letter from applicant transmitting information on onsite AC power system bus tie interlocks October 12, 1982 Letter to applicant transmitting Supplement No. 2 to Safety Evaluation Report (dated September 1982)

October 12, 1982 Meeting with applicant to discuss closing out of Plant Systems Branch issues October 13, 1982 Meeting with applicant to discuss environmental qualification issues October 14, 1982 Meeting with applicant to discuss actions needed to resolve Reactor Systems Branch issues October 14, 1982 Meeting with applicant regarding piping confirmatory issues October 15, 1982 Meeting with applicant to.discuss implementation of fire protection*items St. Lucie 2 SSER 3 A-3

October 15, 1982 Letter from Ebasco transmittting weekly status summary for October 11-15, 1982 October 15, 1982 Meeting with applicant to discuss light loads issue October 15, 1982 Meeting with applicant to discuss control room design review items October 19, 1982 Letter from applicant transmitting construction/startup progress report for September 1982 October 20, 1982 Letter from applicant advising of its review of Generic Letters October 20, 1982 Letter from Ebasco transmitting minutes of October 6-7 meeting of applicant, Ebasco, and C-E EVP Task Force Managers October 21, 1982 Meeting with applicant to discuss fire protection matters October 21, 1982 Meeting with applicant to discuss licensing actions needed to be completed before license issuance October 25, 1982 Letter from applicant transmitting report, "Response to NRC Questions on Implementation of St. Lucie 2 Rod Bow and Grid Spacing Penalties," CEN-221 (L)-P, October 1982 (proprietary)

October 26, 1982 Letter from applicant transmitting "Final Assessment of St. Lucie 2 Fuel Structural Integrity Under Faulted Conditions, CEN-187 (L)-P, Revision 1-P" and "St. Lucie Unit 2 Fuel and CEA Design Summary Evaluation Report, CEN-222 (L)-P" (both proprietary)

October 27, 1982 Meeting with applicant to discuss pump and valve operability items October 27, 1982 Letter from applicant transmitting information on masonry walls October 27, 1982 Letter from applicant forwarding revision to the loose parts monitoring system training program October 27, 1982 Letter from applicant transmitting responses to findings identified during audit of instrumentation andrcontrol area October 28, 1982 Letter from Ebasco transmitting minutes of October 21 meeting of applicant, Combustion Engineering, and Ebasco

. Task Force Managers

• October 29, 1982 Meeting with applicant to review remaining licensing actions or equipment qualification and to assure all parties under-stand what needs to be done with remaining licensing actions St .. Lucie 2 SSER 3 A-4

October 29, 1982 Letter from applicant transmitting information on core exit thermocouples October 29, 1982 Letter from applicant transmitting information on natural circulation cooldown October 29, 1982 Letter from Ebasco forwarding weekly status summary for October 25-30, 1982 October 29, 1982 Letter from applicant' transmitting "Responses to Questions on CESEC, CEN-225(L)-P 11 (proprietary)

October 29, 1982 Letter from applicant forwarding information on boron dilution system alarm October 29, 1982 Letter from applicant forwarding description of modifica-tions to the Iodine Removal System

. October 29, 1982 Letter from applicant transmitting information to confirm piping analysis open items October 29, 1982 Letter from applicant transmitting "RPS Matrix Mock-Up Fault Isolation and Surge Withstand Qualification Test Report" October 30, 1982 Generic Letter 82-23 -Inconsistency Between Requirements of 10 CFR 73.40(d) and Standard Technical Specifications for Performing Audits of Safeguards Contingency Plans (Security Plan)

November 4, 1982 Letter from applicant forwarding additional information on the boron dilution system alarm November 5, 1982 Letter from Ebasco forwarding weekly status summary for November 1-6, 1982 November 10, 1982 Letter from applicant*transmitting (1) Preservice Inspection Section 3.0 Relief Requests and (2) the Mechanical Preservice Examination of Selected Components of the St. Lucie Plant Unit No. 2 November 15, 1982 Letter from Ebasco transmitting weekly status summary for November 8-13, 1982 November 15, 1982 Letter from applicant forwarding information on perimeter fence of the security system November 19, 1982 Letter from applicant documenting telephone conversation of November 12 concerning vibration testing of reactor vessel internals November 19, 1982 Letter from applicant transmitting construction/start-up progress report for October 1982 St. Lucie 2 SSER 3 A-5

November 22, 1982 Letter from Ebasco transmitting weekly status summary for November 15-19, 1982 November 23, 1982 Letter from Ebasco inviting attendance at December 2 meet-ing of EVP Review Committee November 24, 1982 Letter from applicant advising that meteorological instru-ments are same instruments being used to measure atmo-spheric conditions at Unit 1 November 30, 1982 Meeting with applicant to update Division of Licensing on progress made to complete the plant December 7, 1982 Letter from applicant inviting attendance at final meeting of EVP Review Committee on December 15 December 7, 1982 Letter from applicant transmitting corrected version of Mechanized Preservice Examination of Selected Components December 9, 1982 Letter from applicant transmitting information on small feedwater line break analysis December 9, 1982 Letter from applicant forwarding information on the post-accident sampling system December 9, 1982 Letter from applicant forwarding information on its environmental qualification progr~m December 14, 1982 Meeting with applicant to review remaining licensing action.and to assure all parties understand what needs to be done with remaining licensing actions December 14, 1982 Letter from applicant advising that modifications to the ICC system are in progress, will be included in next FSAR revision December 14, 1982 Letter from applicant transmitting supplemental information on small feedwater line break analysis December 17, 1982 Generic Letter 82 Supplement 1 to NUREG-0737 -

Requirements for Emergency Response Capability December 21, 1982 Letter from applicant regarding construction and operation of.Emergency Operations Facility December 21, 1982 Letter from Ebasco forwarding weekly status summary for December 13-17, 1982 December 22, 1982 Letter from Ebasco forwarding minutes of December 15, 1982 meeting December 22, 1982 Letter from applicant concerning reactor protection system power supply testing St. Lucie 2 SSER 3 A-6

December 22, 1982 Generic Letter 82 Meeting to Discuss Recent Developments for Operating Licensing Examinations

• December 22, 1982 Letter from Ebasco transmitting minutes of December 9 meeting December 22, 1982 Generic letter 82 Problems with the Submittals of 10 CFR 73.21 Safeguards Information for Licensing Review*

December 28, 1982 Generic Letter 82 Filings Relating to 10 CFR 50 Production and Utilization Facilities December 29, 1982 Letter from applicant transmitting "Engineering Evaluation and Functional Testing for the C-E PASS Components and Instrumentation," CEN-229(L)-P (proprietary)

January 10, 1983 Letter from applicant transmitting "Engineering Design Verification Program" (final report), description of the program, and additional information on commitment to assure quality product in design and construction of St. Lucie 2 January 11, 1983 Meeting with applicant to review remaining applicant actions on fire protection and to assure all parties understand what needs to be done to support issuance of license January 11, 1983 Generic Letter 83 Operator Licensing Examination Site Visit January 11, 1983 Meeting with applicant to receive its presentation on the design verification program and the results of the completed program January 14, 1983 Letter from applicant committing to perform inservice inspec-tion of the low pressure turbine discs January 14, 1983 Letter from applicant advising that March 23, 1983 is the load date January 14, 1983 Letter from applicant transmitting modified responses to control room design review items and transmitting 11 NTOL Summary Human Engineering Report on St. Lucie Unit No. 2 Control Room 11 (Supplement #1)

• January 18 - Meetings with applicant to discuss open items in safety April 11, 1983 review January 24, 1983 Letter from applicant transmitting proposed test abstract for performing natural circulation testing and requesting approval of abstract January 24, 1983 Letter from applicant transmitting November and December construction progress reports St. Lucie 2 SSER 3 A-7

January 27, 1983 Meeting with applicant to review remaining applicant actions on fire protection and to assure all parties understand what needs to be done to support issuance of license February 1, 1983 Generic Letter 83 Regional Workshops Regarding Supple-ment 1 to NUREG-0737, Requirements for Emergency Response Capability February 3, *r983 Issuance of Amendment 4 to Construction Permit to permit addition of Florida Municipal Power Agency as co-owner February 8,* 1983 Letter from applicant advising that hard copy readout of meteorological data.will be provided in Unit 2 control room February 9, 1983 Letter from applicant transmitting revised information on fite.protection, including responses to questions February 10, 1983 Letter from applicant advising that new electronic diesel generator load sequencing relays will replace existing relays February 11, 1983 Letter from applicant advising that a set of sketches of plant raceway system were given to staff on December 22 February 14, -1983 Letter from applicant forwarding justification for not implementing, prior to core load, certain control pariel modifications February 15, 1983 Letter from applicant transmitting construction/start-up progress report for January February 15, 1983 Letter from applicant forwarding information on security system perimeter fence February 15, 1983 Letter to apRlicant concerning outstanding engineering and construction work items February 16, 1983 Generic Letter 83 The Nuclear Waste Policy Act of 1982 February 23, 1983 Letter from applicant transmitting revised test abstract for performing natural circulation testing February 23-24, Management review meeting 1983 February 24, 1983 Generic Letter 83 Issuance of NRC Form 398 - Personal Qualifications Statement - Licensee February 24, 1983. Letter from applicant advising that completed forms for equipment items selected for audit by Seismic Qualification Review Team have been forwarded St. Lucie 2 SSER 3 A-8

February 25, 1983 Letter from applicant transmitting report on auxiliary feedwater system pump endurance test February 25, 1983 Letter from applicant transmitting information on installa-tion of source range .nuclear instrumentation isolation device and containment flame impingement shields prior to core load February 25, 1983 Letter from applicant forwarding Revision 1 to evaluation supporting requests for exemption from Section III-G of Appendix R to.10 CFR 50 February 28, 1983 Letter from applicant advising that Radiation Protection Program will be implemented at least five days prior to initial criticality

• February 28, 1983 Submittal of Amendment No. 13 to FSAR March 2, 1983 Letter from applicant transmitting reactor containment building integrated leak rate test report March 2, 1983 Generic Letter 83 Clarification of Surveillance Requirements for HEPA Filters and Charcoal Adsorber Units in Standard Technical Specifications on ESF Cleanup Systems March 3, 1983 Meeting with applicant to discuss axial growth and high burnup fission gas release March 3, 1983 Letter from applicant concerning volume control tank over-pressure protection

• March 3, 1983 Letter from applicant forwarding results of light surveys conducted at remote shutdown panel room March 4, 1983 Letter from applicant forwarding information on post accident sampling system capability March 7, 1983 Generic Letter 83 Definition of 11 Key Maintenance Personnel 11 (Clarification of Generic Letter 82-12)

March 9, 1983 Letter from applicant transmitting reports, 11 Core Protection Calculator, 11 11 Ex-Core Safety Channel, Seismic Qualification Test Report, 11 and 11 Bistable/Auxiliary Trip Unit, Seismic Qua 1 if i cat ion Report 11 March 10, 1983 Letter from applicant transmitting 11 Comprehensive Vibration Assessment Program, Final Summary Report 11 March 10, 1983 Letter from applicant forwarding information on fragmentation.

of embrittled cladding March 10, 1983 Letter from applicant withdrawing request for exemption from certain requirements of 10 CFR 73.21 St. Lucie 2 SSER 3 A-9

.. \

March 11, 1983 Letter from applicant providing augmented information to be used in re-review of audit findings by Human Factors Engineering Branch

• March 15, 1983 Letter to applicant forwarding February 11, 1983 letter from Department of Energy advising that applicant is negotiating

• for a contract with respect to requirements of Nuclear Waste Policy Act of 1982 March 17, 1983 Letter from applicant forwarding map to use as part of license conditions Ma'.ch 18, 1983 Letter to applicant'requesting additional information on Engineered Safety Feature Actuation System March 18, 1983 Letter from applicant forwarding additional information regarding Auxiliary Feedwater Pump Endurance Test Report March 18, 1983 Letter from applicant committing to have non pre-aged batteries replaced after lO*years from purchase date or provide sufficient additional test data and analysis to support extended qualified life beyond 10 years March 18, 1983 Letter from applicant regarding operability of safety-related valves March 18, 1983 Letter from applicant concerning compliance with 10 CFR 50.49, 11 Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants 11 March 18, 1983 Letter.from applicant transmitting information concerning testing of diesel generators by manufacturers and the effects of this change to the safety analysis March 21, 1983 Letter from applicant transmitting 11 Analytical Justification of Seismic Test Adequacy of St. Lucie, Unit 2 CPC and NI Modules in Reactor Protection System Cabinet, 11 Supplement 1 March 21, 1983 Letter from applicant transmitting revised justification for interim operation while containment flame impingement shields are not installed March 21, 1983

• Letter from applicant advising that FSAR Amendment 14 will be issued approximately four months following issuance of operating license March 21, 1983 Letter from applicant forwarding construction/start-up progress report for February March 21, 1983 Letter from applicant transmitting Supplement A to Engineering Verification Report St. Lucie 2 SSER 3 A-10

March 22, 1983 Letter from applicant forwarding present schedule for installation of TSI shields .

March 22, 1983 Letter from applicant_ forwarding final response to require-ment of NUREG-0737, Item IJ.D.1, "Performance Testing of Boiling Water Reactor and Pressurized Water Reactor Relief and Safety Valves" March 22, 1983 Board Notification 83 Failure of GE AK-2 Trip Breakers March 23, 1983 Generic Letter 83 Implementation of Regulatory Guide 1.150, "Ultrasonic Testing of Reactor Vessel Welds During Preservice and Inservice Examinations, Revision 111 March 24, 1983 Letter from applicant regarding containment ventilation system Technical Specifications March 24, 1983 Letter from applicant advising of fuel assembly modifications March 24, 1983 Generic Letter 83 Transmittal of NUREG-0977 Relative to the ATWS Events at Salem Generating Station, Unit No. 1 March 24, 1983 Letter from applicant advising that plant will be ready to

• 1oad fuel by approximately March 31 and requesting operating license be granted March 25, 1983 Letter from applicant forwarding information on portions of initial test program which may not be completed by core load March 25, 1983 Letter from applicant transmitting corrective action plans of Engineering Verification Program Report Supplement A March 30, 1983 Letter from applicant in response to Generic Letter 83-102 concerning TMI Action Plan Item II.K.3.5, Automatic Trip of Reactor Coolant Pumps March 30, 1983 Letter from applicant advising that baseline leak testing will be completed prior to initial criticality (in lieu of prior to core load) and a preliminary report will be submitted at that time March 30, 1983 Letter from applicant regarding testing of Engineered Safety Features Actuation System actuation devices March 31, 1983 Letter from applicant providing information on Qualified Safety Parameter Display System and loss of all AC power St. Lucie 2 SSER 3 A-11

• i APPENDIX B.

PRINCIPAL CONTRIBUTORS V. Nerses Project Management J. Lee Project Management H. Polk Structural Engineering T. Chang Seismic Qualification M. Haughey 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 G. Hammer Mechanical Engineering M. Hartzman Mechanical Engineering M. Hum Materials Engineering J. Kennedy Environmental Qualifcation.

J. Guttman Reactor Systems E. Throm Reactor Systems H. Balukjian Core Performance Y. Hsii Core Performance

0. Chopra Power Systems D. Serig Human Factors D. Perrotti Emergency Planning Gage Babcock Brookhaven National Lab.

• Idaho National Engineering Laboratory (EG&G)

Battelle Pacific Northwest Laboratories Argonne National Laboratory St. Lucie 2 SSER 3 B-1

APPENDIX C PSI Relief Request Evaluation

)

I. INTRODUCTION This appendix was prepared with technical assistance of DOE contractors from the Idaho National Engineering Laboratory.

For nuclear power facilities whose construction permits were issued on or after July 1, 1974, 10 CFR 50.55a(g)(3) specifies that components shall meet the pre-service examination requirements set forth in the Edition and Addenda of Sec-tion XI of the ASME Boiler and Pressure Vessel Code applied to the construction of the particular component. The provisions of 10 CFR 50.55(g)(3) also state that the components (including supports) may meet the requirements set forth in subsequent Editions and Addenda of this Code which are incorporated by reference in 10 CFR 50.55a(b), subject to the limitations and modifications listed therein.

The applicant has stated that the preservice inspection program shall be in accordance with Summer 1978 Addenda, 1977 Edition of Section XI of the ASME Code to the extent practical as required by 10 CFR 50.55a. In a submittal dated November 10, 1982, the applicant requested relief from certain preservice inspec-tion requirements for St. Lucie Nuclear Plant, Unit No. 2. The relief requests were supported by information pursuant to 10 CFR 50.55a(a)(2)(i). Therefore, our evaluation consisted of reviewing the applicant 1 s submittal to the require-ments of the above referenced Code, and determining if relief from the Code requirements was justified.

• As a result of its review of this information, we have determined that certain preservice examinations are impractical, and that performing these required examinations would result in hardships or unusual difficulties without a compen-sating increase in the level of quality and safety. The basis for this conclu-sion is discussed in the subsequent paragraphs of this report.

II. TECHNICAL REVIEW CONSIDERATIONS A. The construction permit for St. Lucie Nuclear Plant, Unit No. 2, was issued on May 2, 1977. In accordance with 10 CFR 50.55a(g)(3), components (including supports), which were classified as ASME Code Class 1 and 2, must be designed and provided with access to enable the performance of required preservice *and inservice examinations set forth in Section XI of editions and addenda of the ASME Code applied to the construction of the particular component.

B. Verification of. as-built structural integrity of the primary pressure boundary is not dependent on the Section XI preservice examination. The appli-cable construction codes to which the primary pressure boundary was fabricated, contain material, design, fabrication, examination, and testing requirements, which, by themselves, provide the necessary assurance that the pressure bound-ary components are capable of performing safely under all operating conditions St. Lucie 2 SSER.3 C-1

reviewed in the FSAR and described in the plant design specification. As a part of these examinations, all of ~he primary pressure boundary full penetra-tion welds were examined volumetrically (radiographed), and the system was subjected to hydrostatic pressure tests.

C. The intent .of the preservice examination is to establish a reference or baseline prior to the initial operation of the facility. The results of sub-sequent inservice examinations can then be compared with the original condition to determine if changes have occurred. If review of the *inservice inspection results shows no change from the original condition, no action is required. In the case where baseline data are not available, all indications must be treated as new indications and evaluated accordingly.Section XI of the ASME Code con-

.tains acceptance standards which may be used as the basis for evaluating the acceptability of such indications. Therefore, conservative disposition of defects found during inservice inspection can be accomplished, even though pre-service information is not available.

D. Other benefits of the preservice examination include providing redundant or alternative volumetric inspection of the primary pressure boundary using a test method different from that employed during the component fabrication. Suc-cessful performance of preservice examination also demonstrates that the welds so examined are capable of subsequent inservice examination using a similar test method.

In the case of St. Lucie Nuclear Plant, Unit.No. 2, a large portion of the pre-service examination required by the ASME Code was performed. We have concluded that failure to perform a 100% preservice examination of the welds identified below will not significantly affect the assurance of the initial structural integrity.

E. In some instances where the required preservice examinations were not per-formed to the full extent specified by the applicable ASME Code, we will require that these examinations or supplement examinatio~s be conducted as part of the inservice inspection program. We have concluded that requiring supplemental examinations to be performed at this time (before plant startup) would result in hardships or unusual difficulties without a compensating .increase in the level of quality and safety. The performance of supplemental examinations, such as surface examinations, in areas where volumetric inspection is difficult will be more meaningful after a period of operation. Acceptable preoperational in-tegrity has already been established by similar ASME Code,Section III fabri-cation examinations.

• In case where parts of the required examination areas cannot.be effectively examined because of a combination of component.design or current inspection technique limitations, we will continue to evaluate the development of new or improved examination techniques. As improvements in these areas are achieved, we will require that these new techniques be made a part of the inservice examination requirements for the components or welds which received a limited preservice examination.

• Several of the preservice inspection relief requests involve limitations to the examination of the required volume.of a specific weld. The inservice inspec-tion (ISI) program is based on the examination of a representative sample of St. Lucie 2 SSER 3 C-2

welds to detect generic degradation. In,the event that the welds identified in the PSI relief requests are required to be examined again, we will evaluate the possibility of augmented inservice inspection during our review of the appli-cant's initial 10-year ISi program. An augmented program may include increas-ing the extent and/or frequency of inspection of accessible welds.

III. EVALUATION OF RELIEF REQUESTS The applicant requested relief.from specific preservice inspection requirements for St. Lucie Nuclear Plant, Unit No. 2, .in a submittal dated November 10, 1982.

The appl1cant provided a summary description, with drawings and tables, identi-fying the limitations of the mechanized examination of the reactor vessel due to physical restraints and inspection instrumentation. For limitations to the

. examination of piping system and other vessel welds, the .applicant identified the component location, data package, examination technique, scan angle, con-figuration/limitations, and a quantitative estimate of the examination coverage.

Based on the information submitted by the applicant and our review of the design, geometry, and materials of construction of the components, certain preservice requirements of the ASME Boiler and Pressure Vessel Code,Section XI have been determined to be impractical. In addition, imposing these requirements would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety. Therefore, pursuant to 10 CFR 50.55a(a)(2),

our conclusions that these preservice requirements are impractical are justi-fied as follows. Unless otherwise stated, references to the Code refer to the ASME Code,Section XI, 1977 Edition, including Addenda through Summer 1978.

A. Relief Request No. 1, Examination Category B-A, Class 1 Pressure Retaining Welds in Reactor Vessels and Examination Catagory B-D, Class 1 Full Pene-tration Welds of Nozzles in Vessels.

Code Re(uirement: Class 1 pressure retaining welds in the reactor pressure

• vessel RPV) and full penetration welds of nozzles in vessels are required to receive a preservice volumetric examination in accordance with ASME Code Section XI, Table IWB-2500-1, Categories B-A and B-D.

Code Relief Request: Relief is requested from performing volumetric exami-nation of 100% of the required volume on nineteen (19) reactor pressure vessel welds and ten (10) full penetration welds in the reactor pressure vessel nozzles.

Reason for Re9uest: Geometric configuration and permanent attachments prohibit 100% ultrasonic examination coverage of the Code required examination volume.

Staff Evaluation: 'The relief request is acceptable based on the following cons1derat1ons:

1. The RPV and RPV Closure Head welds were subjected to 100% manual ultrasonic examination, OD and ID, both in-process (prior to final stress relieving),

and post-hydro, prior to preservice inspection;

2. Additional manual scans were conducted from the outside surface of the RPV (where accessible) to complement the inside surface examination cover-age. Overall, considering all angles used for examination, the preservice St. Lucie 2 SSER 3 C-3

examination coverage for all RPV,welds averages 97% with no one weld receiving less than 83% coverage.

3. The subject vessel welds received radiographic and surface examination in accordance with ASME Code Section III, Class 1 requirements.

4. The subject vessel welds received a system hydrostatic test in accordance with ASME Code Section III requirements.

8. Relief Request No. 2, Examination Category 8-8, Class 1 Pressure Retaining Welds in Vessels Other Than Reactor Vessels Code Requirement:. Class 1 pressure retaining welds in vessels other than reactor vessels are required to receive a preservice volumetric examination in accordance with ASME Code Section XI, Table IW8-2500-1, Category 8-8.

Code Relief Request: Relief is requested from performing volumetric examination of 100% of the required volume on four (4) steam generator circumferential head welds and one (1) pressurizer head weld.

Reason for Re9uest: Geometric configuration and permanent attachments prohibit 100% ultrasonic examination coverage of th~ Code requ~red examination volume.

Staff Evaluation: The relief request is acceptable b~sed on the following cons1derat1ons:

1. The ultrasonic volumetric examinations performed on the subject welds, for preservice examination, average over 90% of the Code required volume for each weld. *

2. The _subject vessel welds received radiographic and surface examination in accordance with ASME Code Section III, Class 1 requirements.

3. The subject vessel welds received a system hydrostatic test in accordance with ASME Code Section III requirements.

C. Relief Request No. 3, Examination Category 8-D, Class 1 Full Penetration Welds of Nozzles in Vessels

• Code Requirements: Class 1 full penetr~tion welds of nozzles in vessels are required to receive a preservice volumetric examination in accordance with ASME Code Section XI, Table IW8-2500-1, Category 8-D.

Code Relief Request: Relief is requested from performing volumetric examina-tion of 100% of the Code required volume on six nozzle-to-vessel welds on the pressurizer and six nozzle-to-vessel welds on steam generators.

Reason for Request: Geometric configuration and permanent attachments prohibit*

100% ultrasonic examination coverage of the Code required volume.

Staff Evaluation: The relief request is acceptable based on the following considerations:

St. Lucie 2 SSER 3 C-4

1. Additional ultrasonic techniques were employed, where practical, to achieve the Code required volume. In all cases, 100% of each weld root was examined in one direction by at least one angle. In most cases, 100%

of the required examination volume was examined in one direction by one angle.

2. The subject nozzle welds received radiographic and surface examination in accordance with ASME Code Section III, Class 1 requirements.

3. The subject vessel welds received a system hydrostatic test in accordance with ASME Code Section III requirements.

D. Relief Request No. 5, Examination Category B-J, Class 1 Pressure Retaining Dissimilar Metal Welds in Piping Code Requirement: Class 1 pressure retaining dissimilar metal welds in piping are required to receive preservice volumetric and surface examinations in accordance with ASME Section XI, Table IWB-2500-1, Category B-J.

Code Relief Request: Relief is requested from performing volumetric exami-nation of 100% of the required volume of the sixteen dissimilar metal welds (safe-end welds) used in the inlet and outlets of reactor coolant pumps.

Reason for Request: Geometric configuration of the safe-end welds prevents obtaining the required 100% volumetric examination coverage.

Staff Evaluation: This relief request is acceptable based on the following cons1derat1ons:

1. The applicant performed a thorough study to establish a supplementary ultrasonic technique or an additional alternativ~ examination. This study included use of a welded mockup, which duplicated the materials and welds used in the safe-end welds. Review of the results of this study indicates that ultrasonic examinations were performed to the maximum extent possible where the geometric configuration permitted.

2. Two of the sixteen welds received 100% volume coverage from two sides of the welds. Eight other welds received 100% volume coverage from one side of the welds.

3. The subject welds received radiographic and surface (penetrant) examination in accordance with ASME Code Section III, Class 1 requirements.

4. The subject welds received a system hydrostatic test in accordance with ASME Section III requirements.

5. Since a portion of the subject welds are inaccessible, we will evaluate the possibility of an augmented inservice inspection program during our review of the-applicant's initial 10-year inservice inspection program.-

St. Lucie 2 SSER 3 C-5

E. Relief Request No. 6, Examination Category B-J, Class 1 Pressure Retaining Welds in Piping Code Requirement: Class 1 pressure retaining piping welds are required to receive preservice volumetric and surface examination in accordance with ASME Section XI, Table IWB-2500-1, Category*s-J.

i Code Relief Request: Relief is requested from performing preservice volu-metric examinations of inaccessible portions of 42 circumferential welds, 4 longitudinal welds, and 13 branch pipe connection welds.

Reason for Request: Configuration, permanent attachments and/or structural interferences prohibit 100% ultrasonic examination coverage of the required volume.

Staff Evaluation: This relief request is acceptable based on the following considerations:

1: The applicant has supplemented limited coverage, where possible, using additional angles and scan directions. The applicant has made a commitment to submit the quantitative coverage limitations for the welds to be examined following hot functional testing; however, sufficient information has been submitted to conclude that meeting the code-required examinations is impractical because of accessibility.

2. The subject piping welds received radiographic and surface (penetrant) examination in accordance with ASME Code Section III, Class 1 requirements.

3. The subject welds received a system hydrostatic test in accordance with ASME Section III requirements.

F. Relief Request No. 7, Examination Categories B-L-2 and B-M-2, Class 1

. Pump Casings and Valve Bodies

• Code Requirement: Class 1 pump casing and valve body internal surfaces are required to receive preservice visual (VT-1) examinations in accordance.with ASME Section XI, Table.IWB-2500-1, Categories B-L-2 and B-M-2.

Code Relief Re uest: Relief is requested to substitute fabrication surface exam1nat1on PT for the preservice ASME Code Section XI VT-1 examination of the internal surfaces.

Reason for Request: Surface examination (PT) of pump and valve internal surfaces was performed during manufacture. Disassembly of pumps and valves solely to perform a preservice visual examination of the internal surfaces is a major effort and would impose an undue burden.

Staff Evaluation: Disassembly of pumps and valves to perform a preservice visual examination is an impractical requirement, since the fabrication NDE requirements exceed the PSI visual examination requirements. Therefore, this relief request is acceptable.

St. Lucie 2 SSER 3 C-6

G. Relief Request No. 8, Examination Category C-A, Class 2 Pressure Retaining Welds in Pressure Vessels Code Requirement: Class 2 pressure retaining welds in pressure vessels are required to receive a preservice volumetric examination in accordance with ASME Code Section XI, Table IWC-2500-1, Category C-A.

• Code Relief Request: Relief is requested from performing volumetric exami-nation of 100% of the required volume on six, class 2 steam _generator welds.

Reason for Request: Configuration, permanent attachments, and/or structural interferences prohibit 100% examination coverage of the required examination volume.

• Staff Evaluation: This relief request is acceptable based on the following cons1derat1ons:

1. For all the subject welds, the ultrasonic examination covers 100% of the weld root. For 5 of the 6 welds, 100% of the required volume was examined from at least one side. In all cases, the missed volume is minimal, amounting to 6% for one angle in the worst case.

2. As part of ASME Section III fabrication, the subject welds received both radiographic and surface examinations.

3. The subject welds received a system hydrostatic test in accordance with ASME Section III *requirements.

H. Relief Re uest No. 9 Examination Cate or C-8 Class 2 Pressure Retainin Nozz e Weds 1n Vessels Code Requirement: Class 2 pressure retaining nozzle welds over 1/2 inch nominal thickness in vessels are required to receive preservice volumetric examination in accordance with ASME* Section XI, Table IWC-2500-1, Category C-8.

Code Relief Request: Relief is requested from performing preservice volu-metric examinations of inaccessible portions of four steam generator nozzle welds and four shutdown cooling heat exchanger nozzle welds.

Reason for Request: The shutdown cooling heat exchanger welds are totally inaccessible to both RT and UT methods, due to a welded collar placed over the welds. For other nozzles, configuration, permanent attachments, and/or structural interferences prohibit 100% ultrasonic examination coverage of the required volume.

Staff Evaluation: T~is ~elief request is acceptable based on the following cons1derat1ons:

1. The shutdown cooling heat exchanger nozzle welds received surface examination during fabrication and were -then covered with a welded rein-forcing collar. The ASME Code Section III rules used for fabrication of this type of Class 2 nozzle weld, did not require volumetric (radiographic) examination.

St. Lucie 2 SSER 3 C-7

2. For the steam generator nozzle welds, the volume missed by ultrasonic examination is minimal, amounting to 2% in the-worst case, and affecting only one of two different examination angles.

3. As part of ASME Section III fabrication, the steam generator nozzle welds received both radiographic and surface examinations.

3. The subject welds received a system hydrostatic test in accordance with ASME Section III requirements.

4. Since the shutdown cooling heat exchanger nozzle welds are not accessible for examination, we will evaluate the possibility of an augmented inservice inspection program, such as incr*eased visual examinations, during our review of the applicant's initial 10-year inservice inspection program.

I. Relief Request No. 10, Examinations Category C-F, Class 2, Pressure Retaining Welds in Piping

• Code Requirements: To meet Section XI, Table IWC-2500-1, Category C-F, Class 2 pressure retaining piping welds over 1/2 in. nominal wall thickness are required to receive preservice surface and volumetric examinations; pressure retaining welds 1/2 in. and under nominal thickness are required to receive a preservice surface examination.

Code Relief Request: Relief is requested from performing preservice volumetric examinations of inaccessible portions of 14 welds and surface examinations of inaccessible portions of 3 welds.

Reason for Request: Configuration, permanent attachments, and/or structural interferences prevent 100% examination coverage.

Staff Evaluation: This relief request is acceptable based on the following cons1derat1ons:

1. For the four main steam line longitudinal seam welds, obstructed by welded saddles, the subject welds received 100% radiographic and surface (magnetic particle) examination during fabrication. All other welds received 100%

radiographic examination.

2. For all limited ultrasonic coverage, a minimum of 83% of the required coverage was obtained. The applicant has made a commitment to submit the quantitative coverage limitations for the 9 welds to be examined following hot functional testing; however, sufficient information has been submitted to conclude that meeting the exact code requirement is impractical.

3. For the limited surface examinations, a minimum of 83% of the required surface areas were examined.

4. The subject welds received a system hydrostatic test in accordance with ASME Section III requirements.

St. Lucie 2 SSER 3 C-8

J. Relief Request No. 11, Examination Category C-F, Pressure Retaining Welds in Piping - Containment Spray System Code Requirement: Class 2 piping*welds with 1/2 in. or less nominal wall thickness are required to receive preservice and inservice surface examination in accordance with ASME Section XI, Table IWC-2500-1, Category C-F.

Code Relief Request: Relief is requested to exempt open-ended portions of con-tainment spray system piping from inservice* surface examinations.

Reason for Request: The containment spray system piping is not required to operate during normal system operation. Following initial inspection and test-ing, the containment spray piping downstream of the 2nd isolation valve outside containment is ~ubjected to no pressure transients and no temperature* transients other than ambient containment building/auxilliary building temperature. Thus, the applicant states that there is no subsequent mechanism for failure.

Also, ASME Section XI, Table IWC-2500-1, Examination Category C-H, Note 1,

• exempts open ended portions of systems from VT-2 tests.

Staff Evaluation: This relief request is applicable for ISi only and will be included in our review of the initial ISi plan. The applicant has performed examinations equivalent or superior to the required preservice examination during fabrication. The applicant indicated that all shop welds covered by the subject relief request had received, for Section III fabrication, both surface and raaiographic examination. The field welds received radiographic examination.

Out of 64 total welds covered by this request, 32 are shop welds. The surface examination applied to the 32 shop welds thus meets 10 CFR 50 paragraph 50.55a (b)(2)(iv)(A), which req~ires appropriate Code Class 2 pipe welds in residual heat removal systems, emergency core coolant systems, and containment heat removal systems to be examined. The extent of these examinations for these systems is to be determined by the requirements of paragraph IWC-1220, Table IWC-2520 Category C-F and C-G, and paragraph IWC-2411 in the 1974 Edition and Addenda through the Summer 1975 Addenda of Section XI of the ASME Code.

K. Relief Request No. 12, Examination Cate.gory C-F, Pressure Retaining Welds in Piping - Component Cooling Discharge From Containment Coolers Code Requirement: Class 2 piping welds with 1/2 in. or less nominal wall thickness are required to receive preservice and inservice surface examination in accordance with ASME Section XI, Table IWC-2500-1, Category C-F:

Code Relief Request: Relief is requested from performing surface examina-tion during inservice inspections (ISi).

Reason for Request: The applicant states that exemption from performing surface examination of the Class 2 portions of the piping system is provided in a later Edition and Addenda of ASME Code Section XI, adopted by 10 CFR 50.55a(b).

Staff Evaluation: This relief request is applicable for ISI only and will be included 1n our review of the initial ISi program. The applicant has performed examinations equivalent or superior to the required preservice examinations St. Lucie 2 SSER 3 C-9

during fabrication. The applicant indicated that all shop welds covered by this relief request and subject to examination plus thirteen welds in this system which were not subject to examination have received magnetic particle surface examinations. These fabrication examinations cover a substantial number of the welds in this system and 10 CFR 50.55a(b)(iv) allows the extent of examination to be as required in the ASME Code Section XI, 1974 Edition, 1975 Addenda.

L. Relief Request No. 13, Ultrasonic Calibration Blocks Code Requirement: Calibration blocks for ASME Code Section XI examinations are required to meet Section XI, Appendix III,Section V, Article 4, or Sec-tion V, Article 5 requirements, as specified in Section XI, IWA-2232.

Code Relief Request: Relief is requested for:

1. Use* of a flat~ SA-533 Grade A, calibration block for examination of SA-516 Grade.70, 42 in. diameter primary coolant piping hot legs.

2. Use of a flat calibration block for examination of 36 in. diameter primary coolant piping cold legs.

3. Use of a 34 in. diameter calibration block for examination of 36.25 in.

diameter main steam piping welds.

4. Use of reactor vessel calibration blocks with the 3/4 T straight beam calibration hole closer to the end of the block than allowed by the ASME Code,Section V, Article 4.

Reason for Request: The SA-533 material is provided for by ASME Section XI, Appendix III, III-341(c). Both Articles 4 and 5 of Section Vallow flat calibration blocks for items greater than 20 in. diameter. In addition the flat blocks meet the non-mandatory Appendix V of Article 5 of the ASME Code Section V. Use of a smaller diameter (34 in.) calibration block on 36.25 in.

piping will yield a more sensitive examination. The 3/4 T straight beam holes in the reactor pressure vessel calibration blocks pose no problem during exam-ination calibration and are provided for in a pending Code Case.

Staff Evaluation: Consideration of the items to be examined and provisions .in the ASME Code, indicate that use of the requested calibration blocks will not reduce examination effectiveness. Therefore, this relief request is acceptable.

IV. CONCLUSIONS Based on the foregoing, we have determined, pursuant to 10 CFR 50.55a(g)(3),

that certain Section XI required preservice examinations are impractical, and compliance with the requirements would result in hardships or unusual difficul-.

ties without a compensating increase in the level of quality and safety.

Our technical evaluation has not identified any practical method by which the existing St. Lucie Unit 2 can meet all the specific preservice inspection requirements of Section XI of the ASME Code. Requiring compliance with all the exact Section XI required inspections would delay_ the startup of the*plant in order to redesign a significant number of plant systems, obtain sufficient St. Lucie 2 SSER 3 C-10

replacement components, install the new components, and repeat the preservice examination of these components. Examples of components that would require

• 1 redesign to meet the specific preservice examination provisions are the reactor vessel, primary coolant pumps, and a significant number of the piping and component support systems. Even after the redesign effort, complete compliance with preservice examination requirements probably could not be achieved. However, the as-built structural integrity of the existing primary pressure boundary has already been established by the construction code fabrication examinations.

Based on our review and evaluation, w~ contlude that the public interest is not served by imposing certain provisions of Section XI of the ASME Code that have been determined to be impractical. Pursuant to 10 CFR 50.55a(a)(2), we have allowed relief from these requirements which are impractical to implement and would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

• St. Lucie 2 SSER 3 C-11

APPENDIX D EQUIPMENT REQUIRING REPLACEMENT PRIOR TO PLANT STARTUP (Category 3.11.4.1.1)

No equipment in this category St. .Lucie 2 SSER 3 D-1

APPENDIX E EQUIPMENT REQUIRING ADDITIONAL INFORMATION OR CORRECTIVE ACTION (Category 3.11.4.1.2)

Deficiency/

Equipment Corrective Item Manufacturer Model No. Action Limit Switch Namco EA-180 Series QI Solenoid Valve Asco HTX Series RPS Solenoid Valve Asco RFHV Series RPS Local Control Station Brown-Boveri Various RTS Starters Brown-Boveri Various RTS Pump Motor Westinghouse 3840787 QC Pump Motor Westinghouse 5010P39VSWF QC Fan Motor Westinghouse L-987971 QC Fan Motor Westinghouse TBDP/7908 QC Fan Motor Westinghouse TBDP/7906 QC Pump Motor GE 5K811043C16 QC Pump Motor ( Seismens-Allis EL85117-90301-1 QC Transmitter l) Barton 764 RTS Transmitte/ 1) Barton 763 RTS Valve Operator Li mi torque SB, SMB Series QI Temperature Element RDF Various RTS Electrical Penetrations Conax 7310 Series S, QI Conductor Modules Conax Various S, QI Instrument Cable Rockbestos Firewall III Coax RTS Jumper Wire Teledyne Thermatics Tefzel 280 QI Splices Raychem WCSF-N RTS Electric Heating Coil Watlow 1.5/30 KW RTS Interlocking Relay System Control (1) These transmitters are the subject of a 10 CFR 21 notification.

Additional corrective action may be required at a future date.

St. Lucie 2 SSER 3 E-1

\

APPENDIX F EQUIPMENT CONSIDERED ACCEPTABLE OR CONDITIONALLY ACCEPTABLE (Category 3.11.4.1.3)

Deficiency/

Equipment Corrective Item Manufacturer Model No. Action Transmitter Rosemount 1153 Series B A Medium Voltage Power Cable Okonite B/M DIS A Cable Pulling Lubricant Bishop Electric Bishop #45 Radiation Detector General Atomic RD-23 A Radiation Detector General Atomic RD-8 A Valve Actuator Anchor-Darling 64324-C/001 A Solenoid Valve Valcor V52600-515 A Level Switch Magnetrol A103F-EP A Terminal Block Amerace 616822 A Damper Operator ITT NH-90 Series A Cable Kerite A Motor GE 5K811052C57 A Limit Switch Namco EA-740 A Fan Motor Reliance IXF 8824 Series A Limit Switch Namco EA-170 A Cable Pulling Lubricant Polywater H Analyzer Comsip K-III, K-IV A H§drogen Recombiner Westinghouse Model B A Solenoid Valves Target Rock Various A Solenoid Valve Asco NP Series A St. Lucie 2 SSER 3 F-1

APPENDIX G SAFETY-RELATED SYSTEMS*

IN THE ENVIRONMENTAL QUALIFICATION PROGRAM Function System

1. Emergency Shutdown. Reactor Coolant Chemical &Volume Control

2. Containment Isolation Nitrogen Gas eves Safety Injection Sampling Waste Management Containment Spray Main Steam Feedwater Component Cooling Fire Water, Domestic, &Make up Instrument Air Slowdown Containment Purge Containment Vacuum Relief Hydrogen Sampling

3. Reactor Core Cooling Safety Injection

4. Containment Heat Removal Waste Management Containment Spray Containment Fan Coolers Shield Building Ventilation System

5. Core Residual Heat Removal Main Steam Feedwater Component Cooling

6. Prevention of Significant Sampling Release of Radioactive Containment Purge Material to Environment Containment Vacuum Relief Shield Building Ventilation System Radiation Monitoring

7. Support Systems Uninterruptible Power Direct Current Inverter HVAC Emergency Diesel Generator Shutdown Heat Exchanger St. Lucie 2 SSER 3 G-1

Function System Reactor Protection System Engineered Safety Features Activation System Fuel Pool Cables & Raceways Penetrations St. Lucie 2 SSER 3

APPENDIX H INSTRUMENTATION AND CONTROL SYSTEM BRANCH (ICSB) TRIP REPORT SITE VISIT - ST. LUCIE PLANT UNIT NO. 2

• I. An official site visit by the Instrumentation and Control Systems Branch was conducted at the St. Lucie plant, Unit No. 2 on August 31 through September 2, 1982. The NRC staff was assisted by a consultant from Argonne National Lab (ANL).

• A number of personnel from Florida Power and Light (FP&L), Ebasco, and Combustion Engineering (CE) were available at all times to provide guidance throughout the plant and to answer questions. When problem areas were found, the responsible FP&L personnel pursued the issues and agreed to correct the situation.

In general, the installation of the various instrumentation and control systems appeared to follow the guidelines of applicable design criteria.,

Only a few minor deviations (Part II. below) were noted, which FP&L agreed to correct. Several pieces of equipment to be inspected were not installed at the time of the site visit and this is also noted in Part II. below.

The inspection of selected instrumentation and control equipment and systems followed the outline of an agenda which was submitted to FP&L several weeks prior to the NRC audit.

~

II. Detailed Discussion Following is a detailed summary and discussion on the instrumentation and control systems and equipment observed.

1. Preliminary Discussion

a. The site visit began with a brief tour of the plant which provided an overall, general perspective of the plant layout (included loca-tion and arrangement of various pieces of equipment and associated piping and cabling) and size.

b. The auxiliary building, Emergency Core Cooling System (ECCS), and electrical equipment rooms ventilation systems were discussed. It appears that sufficient low flow and ambient temperature alarms exist in the control room to alert the operator should the ventilation system(s) malfunction. For example, a low discharge flow is annunciated in the control room upon a loss of a supply or exhaust fan. Also, there exists high temperature alarms in the control room for the electrical equipment rooms and the engineered safeguard pump room. The alarms are electrically independent of the St. Lucie 2 SSER 3 H-1

ventilation systems such that a failure of the ventilation system will not disable the operability of the alarming system.

2. Control Room

a. The general layout of the control room was reviewed. All controls

_and indicators were found to be quickly Qnd easily accessible.

The main control boards (RTG) are currently being modified to follow the recommendations made by the Human Factors Engineering Branch (HFEB)during their'control room design review. All labels are being replaced and will consist of black lettering on white. Demarcation lines will be added to show separation between systems. Railing will be added to the extended portion of the boards to prevent operators from inadvertently actuating equipment. Examples of label1ng and demarcation were provided for staff review. The overall control room layout, control board labeling and demarcation, etc., is being covered as part of the HFEB control room design review.

The NRC staff questioned how the .new labeling scheme will identify the redundant electrical divisions/trains. The applicant has referred to an NTOL Summary Human Engineering Repo~t which provides a description of the St. Lucie 2 labeling program. This report is presently under review by the HFEB. This issue is being considered as part of the HFEB control room design review .

.b. The manual reactor trip controls were inspected. The *installation of the controls follows the guidelines recommended by Regulatory Guide 1.62 and Regulatory Guide 1.75. (See Section 7.2.1 of SER.)

c. Adequate annunciation is provided to indicate improper alignment of the motor-operated suction and discharge valves for Component Cooling Water (CCW) pump 2C. (See Section 7.3.5 of SER.)

d. The NRC staff examined the overall display instrumentation important to safety and round it to be sufficient.

This phase of the site visit concentrated on: (1) The bypassed and inoperable status indication for the Engineering Safety Features Actuation System (ESFAS) and Reactor Protection System (RPS); and (2) Post-accident monitoring instrumentation. The bypased and inoperable status indication system appeared to provide adequate annunciation for the Engineered Safety Features (ESF) systems on the main control board. Particular attention was paid to the interaction between the diesel generators and the bypassed and inoperable status system. A separate portion ~f the main control board is dedicated to the diesel generators for control and opera-tional status. There is sufficient interaction such that when a diesel generator is made inoperable, all affected ESF systems will be automatically indicated on the bypassed and inoperable status indication system. The RPS trip channel bypass and inoperable status is not indicated on the main control boards . .However, adequate indication is provided on the four RPS cabineti. The RPS status is St. Lucie 2 SSER 3 H-2

visible to the operator seated *at the control console. Based on the ICSB FSAR review and this site visit, the ICSB concludes that the St. Lucie 2 bypassed and inoperable status indication system is in conformance with R.G. 1.47. (See SER Section 7.5.5.)

The post-accident monitoring instrumentation was also examined.

Although this instrumentation is interspersed with other instrumenta-tion on the main control boards, it is readily identifiable by noting the color of the instrument framework. The framework of all

• post-accident instrumentation is painted white. (See Section 7.4 of SER.)

e. Several cabinets are provided for the reactor coolant system vent valves instrumentation and controls. At the time of the site visit these cabinets were not yet located in their final position nor were all of the components installed in the cabinets. The planned location for these panels was examined.

• f, Annunciation is provided to alert the operator to loss of CCW to the reactor coolant pumps. (See SER Section 7.2.3.)

g. The controls and position indicators for the Low Pressure Safety Injection (LPSI) pump valves which take suction from the refueling water tank and the containment sump were examined and are acceptable. (See SER Section 7.4.4.)

h. The layout of the instrumentation cabinets, engineered safeguards cabinets, and the RPS cabinets in the control room provides easy accessibility, both in the front and the rear. Separation between safety channels (A, 8, C, D, SA, SAB, and SB) appeared to be main-tained in accordance with.R.G. 1.75. Separation is maintained by dedicating a complete .cabinet to a particular channel. The cabinets are clearly identified (labeled or color-coded) as to the safety channel classification.

The isolation cabinets are located on the level beneath the control room. All safety-related cables enter the cabinet on one side and the (non-safety) cable exit on the other side after going through qualified isolators. Adequate separation and isolation appeared to be provided and maintained.

A color-coded cathode ray tube (CRT) display is provided to display overall rod positions as well as the position of selected rods. A digital indicator is provided as a backup display of individual rod position. A lamp matrix showing the core pattern provides annuncia-tion of those rods in the fully inserted position.

j. RPS initiation and status indication are discussed in items 2b and 2d above.

k. Upon examination, it was concluded that sufficient instrumentation and controls exist.in the main control room to provide initiation and status of the engineered safety features equipment/systems.

St. Lucie 2 SSER 3 H-3

1. The controls for operating the safety injection tank isolation valves were examined. Redundant, visual indication of the open or closed status of the valves is provided in the control room as well as independent audible and visual alarms if the valves are not fully open. Key-lock switches are used to control the valve position. The keys are removed when the valves are in the open position. Also, power to the valves is removed after the valves are opened.

m. Instrumentation for the acoustical valve flow devices used to determine the position of the pressurizer safety relief valves and the pressure operated relief valves (PORVs) were not.installed.

n. Temperature, pressure, and level indication are provided on the main control board for the pressurizer relief tank.

o. Redundant control and indicator components mounted on the control boards and cabinets were examined to ensure that adequate physical and electrical separation were maintained. Only one problem area was noted. On RTGB#206, it appeared that the control for V-3495 (SA) was mixed with and not adequately separated from a number of SB controls, and the control for V-3496 (SB) was mixed with and not adequately separated from a number of SA controls. When checked by FP&L staff, it as determined that the switch labels were incorrect.

The NRC staff further verified this by tracing wiring and by viewing installation drawings. The applicant has committed to correct the errors during the human factors upgrade of the cohtrol room which is in progress. The applicant stated that final QC inspection will provide final verification of main control board nameplate identification.

Overall, inspection of the cabling entering the control boards and cabinets verified that the guideines for separation between redundant protection wiring and for separation between protection wiring and control wiring appeared to be followed. A few minor problem areas were noted as follows:

(1) In the rear section of RTGB#206, it was noted that some red coded cables from pull box 78/206 pass directly beneath pull box 77/206 containing green-coded cables. Since the boxes (barriers) are presently open on the bottom, it appears that the physical separation between the redundant wiring is not adequate. To correct this problem, the applicant will install a metal barrier on the bottom of box 77/206 to ensure adequate physical separation. A'field change request has been issued to correct this situation. The applicant stated that final Quality Control (QC) inspections have not been performed yet and that specific instances as described above should be found during the QC inspection phase.

(2) While walking through the RTG boards, it was noted that the conduit and cable ducts within the boards did not appear to have sufficient identification of redundant electrical St. Lucie 2 SSER 3 H-4

divisions. The applicant agreed to provide further identifica*

.. tion of electrical conduit and raceways inside the main control boards and auxiliary instrumentation and control panels within the control room and hot shutdown room. The applicant will use the same channel designations consistent with the remainder of the plants. The staff finds this acceptable.

(3) Throughout the RTG boards, several bundles of various color-coded wire are routed without the use of conduit or cable ducts. No separation between colors is maintained. These wires were found to be ground wires connected to the copper ground bus running throughout the length of the RTG boards.

The installation of these wires is acceptable.

p. Redundant indicators are provided for containment temperature and containment sump liquid temperature. The indicators are located on the RTG boards. (See Section 7.5.3 of the SER.)

q. The controls for the atmospheric dump valves were examined. Both automatic and manual modes of operation are provided. The appli*

cant verified that only the manual mode of operation will be used during normal operation. (See Section 7.7.3 of SER.)

r. The applicant verified, using blueprints, that the containment isolation actuation signal (CIAS) actuates on safety isolation actuation signal (SIAS) as well as high containment pressure or high radiation. (See Section 7.3.6 of SER.)

s. The initiation circuitry for CCW pump 2C was examined. The applicant has taken sufficient measures to ensure that the physical separation and electrical isolation requirements of the ESF SA and SB actuation circuits are not compromised. (See Section 7.3.5 of SER.)

3. Shutdown from Outside the Control Room

a. The remote shutdown panel is located in the electrical equipment room, one level below the control room.

b. The remote shutdown panel consists of three separate cabinets. The left cabinet (facing front) contains SA instrumentation and controls; the middle cabinet contains SAB, MA, MB and non-safety instrumentation and controls; and the right cabinet contains SB instrumentation and controls.

c. All controls and indicators have been adequately identified.

d. The room containing the remote shutdown panel has adequate ventilation and is of sufficient size to accommodate several people *

. e. The potential for damage from missiles, flooding, pipe whip, etc.,

is minimized by a concrete block enclosure around the panel.

St. Lucie 2.SSER 3 H*5

f. **The guidelines for physical separation and electrical isolation of redundant safety and non-safety controls, indicators, and associated wiring have been adhered to for the remote shutdown panel with one exception. The middle cabinet contains SAB, MA, MB and non-safety wiring and components. Adequate separation was not provided on the bottom of the cabinet where the cables entered. The applicant agreed to correct the problem by adding additional metal barriers and covers on the floor of the cabinet. A field change request (FCR 201051-U) has been issued. .

g. During the site visit the NRC staff walked through the procedural steps required in the event of control room *evacuation. This provided the NRC staff with a clear picture of the involved functions such as transfer capability, security systems, control locations, etc.

• Manual transfer switches are installed in boxes at three separate locations in the electrical equipment room. In addition, transfer switches are installed on many of the individual switchgear cabinets for larger pumps and components. The following additional informa-tion was requested and has been received by the NRC staff:

(1). List of all equipment required for hot shutdown, (2) List of all equipment required for cold shutdown, (3) Locations of controls and transfer switches for hot and cold shutdown equipment, (4) A list of transfer switches which provide annunciation in the control room when in the isolated position, and (5) Electrical classification of controls (non-IE or lE).

The NRC staff has reviewed the additional information supplied by

• the applicant and finds it acceptable. Based on the site visit and the FSAR review for development of the SER, the staff judges that plant shutdown can be accomplished from outside the control room with redundant safety-related equipment. *

h. Annunciation is provided. in the control room to indicate those components whose control functions have been transferred to the remote shutdown location.

4. Cable Runs and Cable Spreading Area

a. The cable spreading area is located in the electrical.equpment room directly beneath the control room. It essentially consists of several stacks of cable trays suspended from the ceiling.

b. The installation of the cables and cable trays followed the physical separation and electrical isolation guidelines recommended by Regulatory Guide 1.75 with one exception. Because cables were still St. Lucie 2 SSER 3 H-6

being installed, the trays were not covered where required. The applicant had initially committed to install electrical cable tray covers prior to core load. Subsequently, the applicant requested and the staff agreed to extend the completion date to June 1983 because of critical demands on construction trades. Trays and

• cables are color-coded for identification.

c. No high voltage power cables were observed with routing through the cable spreading area.

d. Cable penetrations through the containment wall appeared to follow the physical separation and electrical isolation guidelines recommended by Regulatory Guide 1.75.

5. Reactor Building, Auxiliary Building, and Turbine Building

a. Redundant protection system instruments located throughout the reactor, auxiliary, and turbine buildings were found to be adequately separated. Although all instruments were tagged with labels, channel identification was not obvious. The color coding on associated wiring and conduit had to be ascertained to identify the channel.

b. All instruments are located behind walls or other barriers provided to prevent damage due to missiles, flooding, etc.

c. Separation and independence of piping and wiring to redundant or diverse instruments appeared to be maintained throughout the plant.

(See Item 10. below.)

d. Plant personnel discussed procedures for testing the instrumentation from the various sensors through to the final trip circuitry.

Adequate provisions appeared to be provided for testing the protec-tion instrumentation. (See Items 6.c., 7.d., and 9.c. below.)

e. Physical separation and electrical isolation of the redundant safety buses are maintained. (See Item 11. below.)

6. Reactor Protection System (RPS)

a. Two independent motor-generator sets are provided for control rod power.

b. Adequate physical and electrical separation of the motor-generator sets, associated cabling, and associated switchgear are provided.

c. The NRC staff walked through typical test procedures for the RPS initiating trip circuitry. It appeared that adequate provisions exist for testing the RPS initiating trip circuitry including the reactor trip breakers while the plant is at full power.

St. Lucie 2 SSER 3 H-7

7. ESF Systems and Pump Rooms

a. Separate rooms are provided for each of the High Pressure Safety Injection (HPSI) pumps, LPSI pumps, and containment spray pumps.

They are located on the lower level of the auxiliary building.

b. Physical and electrical independence are maintained between redundant ESF equipment trains.

c. Instruments are located behind walls or other barriers to provide protection against damage from missiles, pipe whip, etc.

d. The NRC staff walked through typical test procedures for the engineered safety features actuation system. It appeared that adequate provisions exist for testing to the maximum extent possible

• the engineered safety features systems while the plant is at power.

e. Cabling and conduit are color-coded to indicate channel identifica-tion. However, instrument identification labels, in general do not provide channel identification.* (See ltem 5.a. above.)

8. Instrument Rooms/Racks Instrument racks are located in the control room and are discussed under Items 2.e. and 2.h.

9. Instrument Piping

a. Several spot checks were made of the instrument piping from the process vessel or pipe to the sensor. In all cases, adequate separation was noted between redundant channels and between safety and non-safety-related channels.

b. Stainless steel tubing is utilized to transmit the variable to the sensor. Adequate protection appeared to be provided to protect against damage from missiles, flooding, pipe whip, etc.

c. In the vicinity of the sensors, valves are provided to isolate the process input and to insert a test input signal.

10. Circuit Traces from Sensors to Final Actuation Devices

a. The wiring for each of the turbine trip sensors and the component cooling water trip sensors was traced from the sensors through conduit to the isolation relays, and from the isolation relays to the RPS cabi~ets in the control room. Adequate identification, physical separation, and electrical isolation appeared to be provided. The boxes containing the isolation relays were opened and inspected.

Special attention was paid to the routing of the turbine trip cables through a manhole in the turbine building. During the design review held one year ago, it was noted that several 4-kV power cables St. Lucie 2 SSER 3 H-8

passed through the same manhole. The deiign had no provisions for barriers between the turbine trip cables and the power cables. The applicant agreed to revise the design to include suitable barriers.

Upon examining the cables in the manhole, it was*noted that the tur-bine trip cables were enclosed in flexible conduit. Adequate separa-tion appeared to be provided. (See Section 7.2.3 of SER.)

b. The instrument piping to the four pressurizer pressure transmitters and the wiring from the transmitters to the RPS and ESFAS cabinets were traced. Adequate identification and physical separation appeared to be provided.

c. The acoustical flow devices used to determine the position of the safety relief valves and the PORVs were not installed.

d. The LPSI pump suction valves*from the refueling water tank and the containment sump are motor-operated with provisions for remote manual actuation from the control room. (See Section 7;4,4 of SER.)

e.

• The wires for the automatic withdrawal signal for the reactor regulating system*were disconnected from the terminal blocks in the RTGB. (See Section 7.7.3 of SER.)

11. Vital Instrumentation and Control Power Supply Installation

a. The vital instrumentation and control power supplies are lcoated in the electrical equipment room. Associated switchgear is easily accessible.

b. Adequate physical and electrical separation appeared to be provided between redundant power supply groups.

c. Batteries, inverters, battery chargers, etc. were inspected and it appeared that adequate installation was provided to protect for damage from missiles, high energy line breaks, floods, etc.

/

St. Lucie 2 SSER 3 H-9

Appendix I FEMA STATUS UPDATE FOR ST. LUCIE 2 Federal .Emergency Management Agency Washington, D.C. 20472 MAR 4 1983 MEMORANDUM FOR: Edward L. Jordan Director, Division of Emergency Preparedness and Engineering Response Office of Inspections and Enforcement 4!uc~~sion FROM: Rich~i~m Assistant Associate Director Office of Natural and Technological,Hazards

SUBJECT:

Status Update for Plant St. Lucie Florida The purpose of this memorandum is to updpte the status of offsite plans and preparedness at Plant St. Lucie, Florida, in the area of "public education and information." This update is warranted because the "Interim Findings," provided the Nuclear Regulatory Commission (NRC) on November 1, 1982, identified.this area as a major deficiency.

Attached is a "status update" (February 7, 1983) provided to this office by the Federal Emergency Management Agency (FEMA) Region IV Regional Director,*

Mr. Major P. May. This update reports on the results of Regional Assistance Committee (RAC)/FEMA review of the revised Florida Radiological Emergency Management Plan and the "exercise" held on January 20, 1983. As a result of plan review and the recent exercise, FEMA believes that the major deficiency has been eliminated and the area of "public education and information" at Plant St. Lucie is now adequate.

FEMA Headquarters concurs with the Regional Director's evaluation that the revised Florida Radiological Emergency Plan for Plant St. Lucie and the exercise of January 20, 1983, demonstrated that the ability to protect the health and safety of the public in the area of .Plant St. Lucie remains adequate.

If you have any questions on this matter please call me or have your staff contact Mr. Fred Sharrocks of my staff at 287-0206.

Attachment As Stated I-1

Federal Emergency Management Agency Region IV 1375 Peachtree Street, NE Atlanta., Georgia. 30309 February 7, 1'983 P~ty~, .

r...:>.

MEMORANDUM FOR: RIC~.RD W. KRIMM, ASST. !l.. SSOC. DIRECTOR O ~ F.. OF NATURAL ~.ND TECHNOLOGICAL H..:t.Z~'RDS, SL FROM: ~-?o/~ional M. jor Director Su"3JECT: Status Op-date for the Interim Findings Report Plant St. Lucie, Florida September 23, 1982 This r:1emorandum is to doceu-nent recept activities -which ha*ve occurred regarding Plant St. Lucie, *Florida.

qn December 9, 1982 a rev!sed Florida Radiological_Ernergency Management Plan was received by FEJ.'.i.A Region IV. A fonnal R.~C review of the plan*was conducted on January 12, 1983 at the FEHA regional office * .From review of the plan it was concluded that the Florida concept of Public Information is now i~ conformance with FEY..A guidance.

The Public Information activities will be coordinated*with the utility and multiple points of release have been eliminated~

These major changes in policy show progress is improving in the public information program.

The. revised Florida plan for p*ublic in~orrnation was tested at

.the recent Plant St. Lucie Exercise on January 20, 1983. The foilowing corr~ents were made at the exercise critique on January 21, 1983 by the FEMA evaluator for public information.

I. E1-!.ERGENCY OPERATIONS, FACILITIES AND RESOURCES:

(working space, internal comrnunicat-ions and displays, co~.munications, security).

Working space was adequate to support necessary operations. A new Emergency NEWS Center is -under construction as a part of the new Emergency Operating Facility. The new ENC will allow for more adequate

~orking space and Tesources. Internal communications for Public Infonnation Staffs were handled well for producing written releases. Displays were adequate I-2

for the briefing room, however in the Public Infor.:iation Office work area there were no visual aids present. Com.TOtinications existed between all points of control and command. The hard.copy equipment appeared to be working at the ENC.

However, press releases transmitted to county Emergency Opera tion*s Centers were not received.

Florida P~~er and Light releases also experienced

• problems in transmission. Security was adequate for both working areas.

II. ALERTING AND MOBILIZATION OF OFFICIALS A..~D ST.Tl.FF:

(Staffing, 24-hour capability, alerting timeliness).

Coun*ty staff for public informa*tion was very busy representing two counties, St. Lucie and Martin County. The 24-hour capability was c;iernonstrated by activating bac}~-up staff. Consideration could be given *to identifying additional help-for county Public Information Officer, as local activity will be of major concern to the media. It ~s very difficult for only one individual to coordinate both counties *. Alerting and rnobil~zation was not demonstrated, as all staff were prepositioned *.

III. E?-'.ERGENCY OPERATIONS MANAGEMENT: (Organization, control, leadership, support by officials, inforniation fro*...* between levels and organizations, decision-making, checklists and procedures).

The E~C c~erated in ~n efficient manner. Consideration should be.given to coordinati°ng host county media activities.

IV. PUBL'IC ALERTING AND NOTIFICATION: (Means of notification, e.g. sirens, vehicles, other systems, notification time-liness). *

!nfo~ation about the Emergency .Broadcast Systei~*rnessages

~as not confirr=ted* in a timely manner. EBS rnes~ages ir.i tia ted by the local gover:nrr,ents were not received at the El~C. !*~(;?dia reoresentatives were not advised of the infor...ation given to the public by way of EBS.

1-3

v. PUBLIC AND HEDIA RELATIONS: (Publications, press facilities, media briefings, news reliase coordination).

Publications and news releases were numerous and frequent, as were rnedia*briefings. Every effort was ta.ken to keep the media informed 0£ emergency activities and situations. The new equipment utilized for conference calls was excellent. This system allowed rnedia direct access to the decision ffial:ers. Some confusion did occur as a result of

, press releases* which were not clearly written.

'Tracking releases was difficult. Consideration should be given to~ better log system as well as verification procedures.

VI. ACCIDENT ASSESS!*!ENT:. (Staff and field operations, monitoring, adequacy of equiprnent, technical calculations, use of PAGs,_/j_ssuance of tirnely recom.~endat~ons).

Not i.pplicable

. VII. ACTIONS TO PROTECT THE. PUBLIC: (Sheltering, evacuation 1 reception and care, transportation).

Not Applicable VIl!. HEALT3, KSDICAL J.J~D EXPOSURE, CONTROL MEASURES:

{Access control, adequacy of eguiprnent and supplies, dosimetry, use of KI, decontamination, medical facilities and treatment).

Not Applicable RECOVERY AND REENTRY OPERATIONS: (Adequacy of Plans and Procedures).

l~ot ce..-nonstrated at the Eme2.*gency News Center.

X. P..ELEV;.J~CE OF THE EXERCISE EXPERIENCE: (Benefit to participate, adequacy of the scenario).

The e::ercise was beneficial to the participants, and provided an opportunitY. to test new procedures and e::cauiprnent. The e>:ercise pointed out areas of both strengths and weaknesses which will help improve future operations. Overall the exercise established the adeguacy of the revised plan to effectively diss~~inate information in a timely manner.

1-4

I. - .

D:::s-.::ci on t.hr: c.:.bove information it is the Regional.Director's c\*aluc..i:ion i:.11.:d.:. the revised Florida Radiological Emergency

.?la11 for Kucle.ar. ?oi.,1e.r Facilities is adeguate to protect the h:;!&1 th and i,:;~;.f e*::.~, of the public i11 the area of Plant St.

Irocie. *

• *' J 1-5

IJ APPENDIX J LETTER FROM DEPARTMENT OF ENERGY

'REGARDING SECTiON 302(b) OF THE

• NUCLEAR WATER POLICY ACT OF 1982 THE SECRETARY OF ENERGY WASHINGTON. D.C. 20585 February 11, 1983 Honorable Nunzio Palladino Chairman U.S. Nuclear* Regulatory Commission 1717 'H. St.*, N.W. .

Washington, O.C. 20555

Dear Mr. Chairman:

As you are aware, Section 302(b) of the Nuclear Waste Policy Act of 1982 states that NRC shall not. issue or renew a license

• fora nuclear pGwer reactor unless the u.tility has stgned 9 contract with the Department of Energy for disposal services, or the Secretary of Energy affiims in writing that a utility is actively and in good faith negotiating with the Department of

• Energy for a contract.

Since the Department has only begun the rulemaking. procedure to develop the contract by publishing the. sta~dard draft contract in the Federal Register on February 4, 1983, utilities requiring NRC actions deemed to be' an issuance or renewal of a license are not able to enter into disposal contracts at this time. We Have identitied five utilities facing this problem (Florida Pow.~r aQd Light, Duke Power, Southern California Edison, Middle S~uth-Services, Pacific Gas & Electric). The utilities have requested that the Secretary "atfirm that they are actively and in good faith negotiating with the Department for a disposal* contract. We have concluded that, during the rulemaking process, the "actively and in good faith negotiations" standard can be met by specific, detajled comments on our proposed contract from a utility.

On a case-by-case basis for each utility listed above that so formally requests and provides sufficient comments on our dr~ft disposal contract, I iQtend to issue a written affirmation to the Commission as provided for under the Act. As of this date, Southern California Edison, Florida Power and Light, and Ouk~

Power Company have provi~ed specific,* detailed comments on o~r draft contract.

McGuire SSER 6 J-1

- 2 Therefore, I hereby certify that Southern California 'Edison Company, Florida Power and Light Company, and Duke Power Company are actively and in good faith negotiating with the

• oepartment of Energy for a nuclear waste disposal contract.

Thank you for your assistance and cooperation.

7}:;'Qj_~

DONALD PAUL HODEL McGuire SSER 6 J-2 -tro.s. GOVERNMENT PRINTING OFFICE1 1983-381-297:3047

NRC FORM 335 1. REPORT NUMBER (Assign1d by DDCJ 111-811 U.S. NUCLEAR REGULATORY COMMISSION NUREG-0843 BIBLIOGRAPHIC DATA SHEET Supp. No. 3

4. TITLE AND SUBTITLE (Add Volume No., if appropri1teJ 2. (Leave blank}

Safety Evaluation Report Related to the Operation of St. Lucie Plant, Unit No. 2 3. RECIPIENT'S ACCESSION NO.

7. 'AUTHOR ISi 5. DATE REPORT COMPLETED MONTH I YEAR April 1983

9. PERFORMING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code} DATE REPORT ISSUED MONTH I YEAR Office of Nuclear Reactor Regulation April 1983 U.S. Nuclear Regulatory Corrunission 6. (Leave blank}

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

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

10. PROJECT/TASK/WORK UNIT NO.

11. FIN NO.

Same as 9 above.

13. TYPE OF REPORT I PE RI 00 cov ERE o (Inclusive dares}

15. SUPPLEMENTARY NOTES 14. (Leave o/ank}

Docket No. 50-389

16. ABSTRACT (200 words or less}

Supplement No. 3 to the Safety Evaluation Report for the application filed by Florida Power & Light Company, et al. for a license to operate the St. Lucie Plant, Unit No. 2 (Docket No. 50-389), located in St. Lucie County, Florida has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Corrunission. The purpose of this supplement is to update the Safety Evaluation Report by providing (1) our evaluation of additional information submitted by the applicants since Supplement No. 2 to the Safety Evaluation Report was issued and (2) our evaluation of the matters the *staff has under review when Supplements 1.and 2 to the Safety Evaluation Report were issued.

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

19. SECURITY CLASS (This report} 21. NO. OF PAGES

18. AVAILABILITY STATEMENT Unclassified Unlimited 20. SECUt'.l'TYf LAS~ f!>'s (jageJ nc ass1 1e

22. PRICE s

NRCFORM335 111-811

UNITED STATES FIRST CLASS MAIL NUCLEAR REGULATORY COMMISSION POSTAGE & FEESPAIO USl'jRC WASHINGTON, D.C. 20555 WASH :I C PERMIT ! ' j g ~

OFFICIAL BUSINESS PENALTY FOR PRIVATE USE. $300