ML19115A348
| ML19115A348 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 06/30/1983 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-0843 S4 | |
| Download: ML19115A348 (40) | |
Text
NUREG-0843 Supplement No. 4 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 June 1983
(_)
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0 NUREG-0843 Supplement No. 4 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 June 1983 0
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0 6/10/83 TABLE OF CONTENTS Page 1 INTRODUCTION AND GENERAL DISCUSSION 1-1 1.1 Introduction . . . . . . . . . . 1-1 1.9 License Conditions . . . . . . . . . . . . 1-1 1.14 Engineering Verification Program (EVP). 1-2 1.14.1 Introduction . . . . . . . . . . 1-2 1.14. 2 Selection Process . . . . . *. . . . . . . . 1-2 1.14. 3 Engineering Verification Process. 1-3 1.14.4 Task Force Conclusion . . . . * . . 1-5 1.14. 5 Staff Review and Evaluation Process 1-5 1.14. 6 Staff Conclusion . . . . . . . . . . *1-5 1.14. 7 Senior Staff Review Team Evaluation 1-5 1.14.8 Conclusion . . . . . . . . . . . . . 1-7 3 DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS . . 3-1 3.11 Environmental Qualification of Safety-Related Equipment 3-1 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS. 5-1 5.4 Component and Subsystem Design . 5-1 5.4.3 Shutdown Cooling (Residual Heat Removal) System 5-1 6 ENGINEERED SAFETY FEATURES 6-1 6.2 Containment Systems. 6-1 6.2.4 Containment Isolation System 6-1 7 INSTRUMENTATION AND CONTROLS. 7-1 7.2 Reactor Protection System. 7-1 7.2.3 Equipment Protection Trips 7-1 7.5 Safety-Related Display Instrumentation . . 7-1 7.5.4 Post-Accident Monitoring Instruments. 7-1 CONDUCT OF OPERATIONS . . 13-1 0
13 13.3 Emergency Planning . . 13-1 St. Lucie 2 SSER 4 iii
TABLE OF CONTENTS (Continued) 0 Page 13.3.2 Evaluation of the Emergency Plan . . 13-1 13.3.5 Conclusion . . 13-1 13.6 Physical Security Plan. 13-1 14 INITIAL TEST PROGRAM . . . 14-1 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 0
St. Lucie 2 SSER 4 iv
0 1 INTRODUCTION AND GENERAL DISCUSSION 1.1 Introduction On October 9, 1981, the Nuclear Regulatory Commission (NRC) staff issued a safety evaluation report (SER) related to the operation of St. Lucie Plant Unit 2. Supplement No. 1 (SSER 1) to the SER was issued in December 1981.
Supplement No. 2 (SSER 2) was issued in September 1982. Supplement No. 3 (SSER 3) was issued in April 1983 in conjunction with the issuance of the Operating License (restricted to 5% power level). In the SER, SSER 1, SSER 2 and SSER 3, the staff identified certain issues where either further information or additional staff or applicant effort was necessary to permit authorization for power operation.
The purpose of this supplement is to update the SER by providing (1) the staff evaluation of additional information submitted by the applicant since SSER 3 to the SER was issued and (2) the results of the evaluation of the matters the staff had under review when the SSER 1, SSER 2 and SSER 3 were issued.
Each of the following sections of this supplement is numbered the same as the section of the SER, SSER 1, SSER 2 and SSER 3 that is being updated, and unless otherwise noted, the discussions are supplementary to and not in lieu of the discussion in the SER, SSER 1, SSER 2 and SSER 3. Appendix A to this supple-ment is a continuation of the chronology. Appendix Bis a list of the principal contributors to this supplement. 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.
1.9 License Conditions Section 1.9 of the SER contained a list of license conditions. The list below provides the number of license conditions at thi6 time:
(1) Axial growth (4.2.3.l(g))
(2) Inservice inspection program for Class 1, 2 and 3 components (5.2.4, 6.6)
(3) Natural circulation cooldown and boron mixing test (5.4.3)
(4) Containment ventilation system minipurge valves (6.2.4)
(5) Barrier for high energy equipment (8.4.1)
(6) Non-safety loads on emergency power sources (8.4.2)
(7) Containment electrical penetrations (8.4.3)
(8) Heavy Loads (9.1.4)
(9) Fire protection (9.5.1)
(10) Emergency diesel engine auxiliary support systems (9.5.4.1)
(11) Radioactive waste management 0
(a) Refueling water storage tank level indication (11.2) .
(b) Waste management system concentrator bottom tanks (11.2).
(c) Continuous oxygen analyzer (11.5)
St. Lucie 2 SSER 4 1-1
(12) Initial test program (14)
(13) NUREG-0737 conditions 0
(a) Control room design review (Section 22, I.D.l)
(b) Reactor coolant system vents*csection 22, II.B.1)
(c) Postaccident sampling capability (Section 22, II.B.3)
(d) In-containment High Range Radiation Manito~ (Section 22, II.F.1(2c)) . .
(e) Inadequate Core*Cooling:Instrumentation (Section 22, II.F.2)
This supplement addresses the licensee's response to the license conditions listed below which required evaluat_ion 'by the staff. It does not address those license conditions that require Region II verification (namely items (4), (6),
(7), (9), (10), (11), (12), (13)(a), (13)(b), and (13)(d) above).
(1) Environmental Qualifications *(3.11)
(2) Continuous Containment Purge System (6.2.4)
(3) Emergency Response Capability (13.3.2.8, I.D.1, -I.D.2)
(4) Physical Security (13.6)* * * '
1.14 Engineering Verifi~ation Program (EVP) 1.14.1 Introduction The Engineering Verification Program (EVP) was developed.by Florida Power &
Light Co. (FP&L) with the purpose of providing additional assurance to the NRC regarding the adequacy of design and installation at the St. Lucie 2 facility.
The program furnished an altern*ative to third party reviews carried out by other applicants.: Because of earlier FP&L efforts to establish confidence in desigh adequacy, the staff agreed to accept the FP&L alternative program.
On January 10, 1983, FP&L submitted a report of their completed EVP on St.
Lucie 2. On March 21, 1983 and March 25, 1983, FP&L*provided supplements to their report. The EVP consists of an independent generation of designs for eight components which were subsequently*compared to the actual component designs approved for plant installation. This independent work was performed by a task force of experienced CE and EBASCO engineers who had no prior involve-ment in the St. Lucie 2 design. The eight components were selected by FP&L from a list of components making up several safety systems. Agreement of the independent designs with the actual designs was the Task Force's means of confirming that design for these components was in accord with good engineering practices. The Task Force subsequently verified correct installation and test for these components. The Task Force reported that.Cl) design, installation and testing is in accord with good engineering practice, (2) no generic process or procedural problems affecting plant safety were detected and (3) the task force has formally concurred with all FP&L corrective action plans to resolve the task force observations.
- 1.14.2 Selection Process The selection of items to be revi.ewed by the Task Force consisted of the following steps: 0 St. Lucie 2 SSER 4 1-2
candidate items included:
randomly selected components from several safety systems components that had multi-discipline interfaces The candidates were.divided into A/E and NSSS items, and at least two NSSS items were chosen. The candidates were also divided by major disciplines*as follows:
- Civil/Structural
- Mechanical Electrical
- Heating, Ventilation and Air Conditioning (HVAC)
Instrumentation and Control At least one item from each discipline was selected; The general boundaries of the items reviewed included:
The component support and/or foundation system including its interface with the building structure.
Equipment-to-piping connection points, e.g. nozzles, weld ends, flanges, etc.
Local power supply, instrumentation and controls.
The items selected for review were:
Safety Injection System, Valve V-3614 (CE)
- Control Room Emergency Cleanup System, Damper, IFCV-2514 (Ebasco)
- Combustible Gas Control System, H2 Recombiner 2A (Ebasco)
Radiation Monitoring System, Area Monitor, GM-22 (Ebasco)
Auxiliary Building, Tornado Door RA-109 (Ebasco)
Main Steam Isolation Valve, I-HCV-08-lA (Ebasco)
ECCS Area Vent System Filter, HEPA Filter (Ebasco)
Specific boundaries were established by the Task Force after the items had been selected. .
1.14.3 Engineering Verification Process The following is a brief summary of the joint Task Force .activities carried out during each of. the three phases for each of the review items comprising the independent EVP:
1.14.3.1 Phase 1 - Engineering Design Verification a
The Task Force first obtained all design inputs considered necessary to perform an independent design review for the items selected. Utilizing these design
- nputs, independent calculations and sketches were generated and compared with .*
he existing calculations and drawings. Differences between the independent and existing designs were documented and analyzed. If the differences were St. Lucie 2 SSER 4 1-3
determined to be acceptable, the rationale was documented and the design review phase was considered complete. If the Task Force was unable to resolve 0
the differences, they were transmitted to the Review Committee for resolution.
The Review Committee consisted of the FP&L Engineering Project Manager, Ebasco Project Engineer, CE Project Manager and the Task Force managers from FP&L, Ebasco and CE. The Task Force always maintained the option of determining whether the resolution was acceptable.
1.14.3.2 Phase 2 - Field Installation Verification Upon completion of the design review phase for a specific item, the independent field installation verification phase was scheduled. The Task Force obtained copies of the latest drawings and other design documents used to install the item and performed an in-place examination to verify the as-built installation against the drawings and documents. Differences were documented and analyzed and if the differences could not be resolved, the same procedures were followed as described in 1.14.3.1.
1.14.3.3 Phase 3 - Start-up Operation Verification Upon completion of the field installation verification phase for a specific item, the independent start-up verification phase was scheduled. The Task Force obtained all applicable performance documents not previously provided in addition to pertinent start-up procedures and start-up test data completed to the date the verification started. A comparison was then made of the perform-ance requirements versus actual performance data based on the start-up testing completed by plant operations. Differences were documented and analyzed and if the differences could not be resolved, the same procedures were followed as described in Section 1.14.3.1.
1.14.3.4 Discussion In the three phases of the EVP, each difference ar1s1ng from the verification process was reviewed against previously established criteria to identify whether the difference was to be categorized as a finding or an observation.
The criteria were (1) an unresolved difference that could affect the safety of the plant or that resulted from either a generic technical process flaw or generic procedural program flaw would be identified as a finding, and (2) an unresolved difference not affecting plant safety but resulting from either an isolated process flaw or isolated procedural program flaw would be identified as an observation.
The process resulted in the generation of 84 differences (often referred to by the EVP Task Force as "discrepancies") based upon comparisons of design, installation and testing information generated by the EVP with the correspond-ing information from the existing plant features. Further investigation of the information already available to the EVP Task Force and subsequent discussions with the St. Lucie 2 project team, in which additional information was provided to the EVP resulted in the resolution of all but eight of the differences.
These eight differences were then classified as ob~ervations when the above 0
mentioned criteria were applied.
St. Lucie 2 SSER 4 1-4
0 1.14.4 Task Force Conclusion The EVP Task Force concluded that the small number of observations and no findings resulting from their verification program confirmed:
Design, installation, and testing was in accord with good engineering
.practice.
Product quality indicated the effectiveness of QA measures.
No generic process or procedural problems affecting plant safety were detected.
1.14.5 Staff .Review and Evaluation Process The number of characteristics for a component's design, installation and testing developed by ,the Task Force was based on the information the Task Force decided was needed to provide an adequate comparison of the EVP results with the actual results. The number varied from 39 for the auxiliary building tornado door to 307 characteristics for the safety injection system valve. The staff reviewed the characteristics for each component and concluded that the range of character-istics was adequate to provide a meaningful*comparison of the EVP results with the results of the actual components.
For each component, the staff performed its review by assigning a lead tech-nical branch for the review and to coordinate the review of other technical branches*who also contributed to the review. The lead technical branch was responsible for determining if they could reasonably expect to reach similar conclusions as that of the Task Force based primarily on the work and results submitted in the reports (i.e., did the Task Force reasonably demonstrate that-work done, evaluated and reported by them support their conclusions?). Further-more, the lead technical branch was responsible for making a determination as to whether the unresolved differences reported by the Task Force indicated that plant wide a problem could exist that affected the safety of the plant.
1.14.6 Staff Conclusion Based on the staff review of the design comparison, field installation and start-up information and on the agreed upon FP&L corrective actions to resolve the eight 11 observations, 11 the staff concluded, in general, that the EVP Task Force reasonably demonstrated that the work done, evaluated and reported by them supports their conclusion. The staff noted an exception regarding the HEPA filter. This is discussed below in Section 1.14.7.
1.14.7 Senior Staff Review Team Evaluation In addition to the staff review described above, a small team of senior staff members from NRR and Region II reviewed the eight observations the Task Force reported in order to establish a position on generic implications of these observations.
0 St. Lucie 2 SSER 4 1-5
The eight observations were addressed in the' staff evaluations. Two of the observations dealt with the lack of proper equipment nameplates or identifica-0 tion tags for the circuits for the MSIV (1 HVC-08-lA) feeder panel and for the HPSI Pump 2A feeder panel. Since there are no design requirements that require a feeder directory within electrical panels and since complete directory assistance is contained in on-site documents, the review team agreed with the conclusion that this type of difference is not of safety significance and has no generic implications.
Five of the observations pertained to the lack of consistent color coding of equipment nameplates in accordance with the FSAR for five of the eight compo-nents verified under this program. The color coding has no effect on safe operation or design of the equipment. All electrical panels and equipment are provided with identification nameplates. It is not required by Regulatory .
Guides or Industry standards that there be a consistent color coding scheme for electrical equipment; however, the FSAR does specify that safety-related equip-ment must be identified by an appropriate color coding scheme. Since there were many other FSAR requirements verified under this program and since this requirement is not safety significant, this type of difference is considered to be isolated and appropriately classified as an observation.
One observation pertained to a discrepancy in the documentation of the chloride content of the stem packing material for the safety injection tank isolation valve. This discrepancy consisted of a potential flaw in a QC procedure regarding certifications required to be made during valve repacking. Inasmuch as this discrepancy is not safety significant and is an isolated procedural flaw, we agree with the conclusion that this has been properly classified as an observation.
The review team has also examined the EVP design of the HEPA filter for the ECCS area ventilation system with respect to the need for inclusion of a demister for protection of the filter. The staff noted that neither the St. Lucie 2 design nor the independent EVP design included a demister. The position of the staff is that under accident conditions, a demister is needed for the protection of HEPA filters experiencing a 100% relative humidity environment with entrained water droplets. On this basis, the staff considered the EVP design not to be "in accord with good engineering practice." The review team held discussions with the EVP project team engineers responsible for the HEPA filter design to ascertain the reason the demister was excluded.
The EVP engineers agreed with the staff on the need to include demister protec-tion for HEPA filters in the type of high moisture environment mentioned above.
However, the EVP engineers maintained that given the location of the HEPA filter for the St. Lucie 2 ECCS area ventilation system and given the ducting pathway any entrained water droplets would need to travel, their judgment was that a water droplet environment is unlikely enough that a demister need not be included.
The review team has considered the staff and EVP project team input and agrees with the position of the staff with respect to the appropriate environment for the design of this system. However, based on the reason for the omission of the demister being a difference of engineering judgment between the staff and the EVP regarding the correct de~ign environment, the review team does not feel 0
St. Lucie 2 SSER 4 1-6
0 that this is a significant deficiency with respect to the adequacy of the EVP results.
1.14.8 Conclusion The review team reviewed the eight observations and concluded that the items were appropriately classified as observations with respect to their safety significance. The review team also concluded that the differences/discrepancies involved were isolated and do not have generic implications.
0 St. Lucie 2 SSER 4 1-7
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0 3 DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3.11 Environmental Qualification of Safety-Related Equipment In Supplement 3 of the SER, the staff provided the results of the review of the St. Lucie Unit 2 equipment qualification program. At that time, outstanding items concerning conformance with the recently issued rule on environmental qualification of electrical equipment in 10CFR50.49 required resolution. In letters dated May 26, 1983 and May 31, 1983, the licensee responded to the staff's request for additional information on this subject.
To address conformance with Section 50.49(b)(2) of the rule concerning nonsafety-related equipment whose failure under postulated accident conditions could pre-vent the satisfactory accomplishment of safety functions, the licensee referred to previous staff reviews.of IE Information Notice 79-22, "Qualification of Control Systems, 11 and Regulatory Guide 1.75, "Physical Independence of Electric Systems." The staff review and evaluation of the IE Information Notice 79-22 response is described in Section 7.7.3 of the SER (NUREG-0843). No design changes or additional equipment qualification are necessary to assure that high energy line breaks do not cause control system failures to complicate events beyond the FSAR analysis. Section 8.4.2 of the staff SER describes the licen-see's conformance with the guidelines in Regulatory Guide 1.75. Based on the above, the staff concludes that the licensee's response to 50.49(b)(2) is acceptable.
The licensee has also addressed the scope of safety-related equipment included in the program. The staff reviewed this response and finds the scope to be consistent with the requirements in 10 CFR 50.49(b)(l) and (c). Furthermore, an updated list of equipment was provided in accordance with 10 CFR 50.49(d) and (i), and the staff found it acceptable. Justifications for interim opera-tion (JIO) were also provided in accordance with 10 CFR 50.49(d) and (i), and the staff reviewed all the JIOs and found them acceptable.
Based on the above evaluation, the staff concludes that all open items identi-fied in Supplement No. 3 have been satisfactorily resolved. The staff further concludes that*the licensee has demonstrated compliance with 10 CFR 50.49. The staff will condition the operating license to require the licensee to have electrical equipment within the scope of 10 CFR 50.49 environmentally qualified as required by 10 CFR 50.49 prior to startup following the first refueling outage but not later than March, 1985.
0 St. -Lucie *2 SSER 4 3-1
0 0
0 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.4
- Component and Subsytem Design 5.4.3 Shutdown Cooling System The St. Lucie Unit No. 2 (S.L.2) Operating License, NPF-16, license condition 2.c.7 requires that prior to exceeding 50% of rated thermal power, either a) pro-vide a report of the San Onofre Unit 2 (S.0.2) Natural Circulation Cooldown and Boron Mixing Test justifying that the test data is applicable to S.L.2 assuring adequate boron mixing during natural circulation cooldown orb) perform the test at S.L.2. In a letter dated June 9, 1983, the licensee stated that due to recent delays of the S.0.2 Test, it appears unlikely that the test at S.0.2 will be completed before S.L.2 reaches 50% power. The licensee had expected the S.0.2 test data to be applicable to S.L.2; therefore the S.L.2 test was not expected to be performed. As a result, little, if any, procedures were prepared and little, if any, analyses or equipment developed for S.L.2 to perform the natural circulation boron mixing test by 50% power. Therefore, the licensee is requesting a change to the requirement from "prior to exceeding 50% of rated thermal power" to "prior to completing the startup test program. 11 FP&L believes this to be justified because the natural circulation cooldown event which occurred at St. Lucie Unit No. 1 in 1977 had demonstrated that the operators were able to borate the reactor coolant system and to shut down the plant with-out endangering the health and safety of the public. S.L.2 is essentially identical to St. Lucie Unit No. 1; therefore, FP&L has confidence in the plant procedures and systems, such that similar results would be expected on S.L.2.
The staff agrees that the St. Lucie Unit 1 natural circulation event demon-strated a successful reactor coolant system (RCS) cooldown and boration, and would generally apply to S.L.2.
The staff notes, however, that the St. Lucie Unit 1 natural circulation cool-down event would not, of itself, provide sufficient basis to satisfy the boron mixing and natural circulation cooldown test requirements associated with RSB BTP 5-1. The operators correctly used all available equipment to accomplish a RCS natural circulation cooldown; however, RSB BTP 5-1 stipulates that the demonstration test be done with safety-related equipment. Nontheless, the staff recognizes the importance of the St. Lucie Unit 1 event in terms of a demonstration of the overall phenomena.
The staff considers that the natural circulation test on S.L.2, should it be necessary to perform, should be carefully planned and analyzed beforehand.
Adequate procedures and operator training would be necessary and the staff would carefully review the manner in which the licensee intends to perform the test and satisfy the requirements of RSB BTP 5-1. By allowing the scheduled delay requested by the licensee and should there be a need to perform the test at S.L.2, sufficient time would be available to develop these plans and pro-cedures without unnecessarily impacting the plant test.
0 St. Lucie 2 SSER 4 5-1
Results of the St. Lucie analysis and the data from the St. Lucie 1 natural circulation cooldown event provide reasonable assurance that S.L.2 could per-0 form natural circulation cooldown with proper boron mixing using only safety grade equipment. The staff concludes that this delay in performing the test on natural circulation and boron mixing will not cause undue risk to the pub-lic health and safety. Therefore, we find it acceptable to modify the licensee condition 2.c.7 to change the requirement as noted above, i.e., from "prior to exceedng 50% of rated thermal power" to "prior to completing the startup test program."
0 St. Lucie 2 SSER 4 5-2
0 6 ENGINEERED SAFETY FEATURES 6.2 Containment Systems 6.2.4 Containment Isolation System Two concerns were identified by the staff in Supplement 3 to the Safety Evalua-tion Report regarding the operability of the mini-purge system following onset of a LOCA. The two concerns are: (1) the possibility of the supply line entry being submerged following onset of a LOCA; and (2) the presence of an unquali-fied damper located between the debris screen and the inboard containment isola-tion valve. Our requirements to resolve these concerns were imposed as license condition 2.C.8 of the St. Lucie Plant Unit 2. Facility Operating License.
By letters dated May 10, 1983 and May 25, 1983, the licensee presented their analysis of the maximum containment water level following a LOCA. The licensee demonstrated by calculation that the maximum water level will be below the inlet of the supply line. The analysis entailed calculating the floodable volume in the lower containment and comparing it to the water inventory available for discharge to the containment. The water inventory accounted for the refueling water tank, primary coolant system, safety injection tanks, boric acid and hydrazine tanks. We have reviewed the licensee's method of analysis, assumptions, and results, and find them to be conservative and acceptable.
This resolves the staff's concern about the supply line entry being submerged following onset of a LOCA.
With respect to the staff's concern regarding the placement of an unqualified damper between the debris screen and the inboard isolation valve in the exhaust line of the mini-purge system, the licensee has informed the staff that the damper has been removed.
Based on our review, and acceptance, of the licensee's containment flood level calculation, and the removal of the unqualified damper in the mini-purge system exhaust line, we conclude that license condition 2.C.8, concerning the opera-bility of the mini-purge system, has been satisfactorily resolved.
0 St. Lucie 2 SSER 4 6-1
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0 7 INSTRUMENTATION AND CONTROLS 7.2 Reactor Protection System 7.2.3 Equipment Protection Trips 7.2.3.1 Post-Trip Review Procedures Recent failures of circuit breakers in reactor protection systems (RPS) have resulted in loss of redundancy of the RPS and at one facility two complete fail-ures to automatically scram. These events resulted in the staff preparing NUREG-1000, 11 Generic Implications of the ATWS Events at Salem Nuclear Power Plant. 11 This report includes a description of the requirements for post-trip review instructions, the problem at Salem, the cause of the failure to detect the first ATWS, and the generic implications. As a result, the NRC has been assessing the adequacy of procedures for reviewing reactor trip events before plant restart.
The staff has reviewed the St. Lucie Unit 2 procedures addressing post-trip reviews. These include two administrative procedures: Number 0010120, 11 Duties and Responsbilities of Operators on Shift, 11 Revision 19, dated October 26, 1982 and Number 0005725, 11 Duties and Responsbilities of the STA, 11 Revision 3, dated February 2, 1983 and Operating Procedure Number 2-0030120, 11 Prestart Check-off List, 11 Revision 6, dated May 13, 1983. Our review included discussions with the applicant's staff. The NRC staff determined from these discussions that many of the actions taken by plant personnel in conducting post-trip reviews is based on plant practices that are not written as procedures.
Based on the above, the staff has concluded that the applicant has addressed the current staff's concerns in this area. In addition, the applicant has committed to provide for staff revision and approval an upgraded post-trip review guidance for staff review within 60 days from the issuance of the full power license. This is expected to be a consolidation of the guidance currently contained in several procedures and unwritten plant practices. The staff concludes that the current guidance and this commitment are acceptable for issuance of a full power license.
7.5 Safety-Related Display Instrumentation 7.5.4 Post-Accident Monitoring Instrumentation 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 submittal of the R.G. 1.97 Evaluation Report (ER) describing how R.G. 1.97 has been met.
0 By *letter L-83-238 dated April 15, 1983, FP&L indicated the schedule for submitting the ER is November 30, 1983. This schedule has been found reasonable and timely and therefore acceptable to the staff:
St. Lucie 2 SSER 4 7-1
0 0
0 13 CONDUCT OF OPERATIONS 13.3 Emergency Planning 13.3.2 Evaluation of the Emergency Plan 13.3.2.8 Emergency Facilities and Equipment 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 comple-tion of the Emergency Response Facilities (ERFs). By letter L-83-238 dated April 15, 1983, FP&L indicated the ERFs schedule is as follows:
The TSC is currently operational except for some construction activity for installing the Safety Parameter Display System (SPDS). The SPDS will be completed at the end of the first refueling outage.
- b. Operational Support Center (OSC)
The OSC is currently operational.
- c. Emergency Operation Facility (EOF)
The EOF is currently under construction and will be completed and opera-tional by October, 1983.
13.3.5 Conclusion The above schedules have been found reasonable and timely and therefore acceptable to the staff. Furthermore, as required by the license, FP&L is maintaining interim emergency support facilities while the construction of the TSC and EOF continues.
13.6 Physical Security Plan In a letter dated May 11, 1983, FP&L submitted a partial rev1s1on (Revision 7) to the 11 st. Lucie Plant Security Plan. 11 This submittal was to* fulfill the license condition 2.D regarding upgrading and reevaluating the St. Lucie 2 vital areas. The staff reviewed the submittal and agreed that the changes are con-sistent with the provisions of 10 CFR 50.54(p) and are therefore acceptable.
0 St. Lucie 2 SSER 4 13-1
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0 14 INITIAL TEST PROGRAM In response to FSAR Review Question 640.4, Florida Power & Light (FP&L) added to the St. Lucie 2 Initial Test Program, by Amendment 6 to the FSAR, a natural circulation test to be conducted at low power (1 to 5% power). This test description, FSAR Section 14.2.12.4I, was accepted as meeting the NUREG-0737 Item I.G.1 requirement.
In a letter dated January 24, 1983~ FP&L.requested approval to conduct the natural circulation testing and training during the precritical, hot functional testing phase of initial testing, in lieu of during the low-power phase. The new test plan would also include a natural circulation test initiated from the stagnant, hot, no-flow condition and using a single steam generator.
With the exception of the follow-units such as Sequoyah 2, McGuire 2, and San Onofre 3, all post-TMI PWR new operating licensees have conducted low-power
(<5%) natural circulation testing and training as a prerequisite to full-power licensing. Because low-power natural circulation operation requires temporary modifications to the reactor protection and engineered safeguards instrumenta-tion systems to prevent inadvertent trips and ESF actuations, this mode of operation requires changes to the facility's Technical Specifications and FSAR Chapter 15 safety analyses. It is therefore necessary for the utilities to perform additional safety analyses, and the staff to evaluate those analyses and authorize additional Technical Specifications exceptions. These analyses have shown the tests can be performed in a safe manner.
By conducting natural circulation testing and training during precritical, hot functional testing, the objectives of I.G.1 can be accomplished within the operating boundaries of existing safety analyses and Technical Specifications.
We, therefore, conclude that performing the natural circulation test as described in the applicant's January 24, 1983 letter is acceptable.
0 St. Lucie 2 SSER 4 14-1
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0 22 TMI-2 REQUIREMENTS 22.2 Discussion of Requirements I.C.9 Long Term Program Plan for Upgrading Procedures Discussion 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 comple-tion of the upgrading and implementation of Emergency Operating Procedures (EOPs). By letter L-83-238 dated April 15, 1983, FP&L indicated the EOPs upgrading and implementation schedules are as follows:
Conclusion The above schedules have been found reasonable and timely and therefore accept-able to the staff.
I.D.1 Control Room Design Review Discussion In item A.1.3 of Appendix E of the Operating License (OL) that was issued on April 6, 1983, the staff decided the statement, "The Remote Shutdown Panel
.SIS block keys will be maintained at RAB control access point" should be deleted for reasons as explained below.
During the course of the control room human engineering discrepancies review, the staff was assured that the Remote Shutdown Panel SIS block keys will be maintained at a location consistent with the necessary key access procedures.
FP&L recently notified the staff that the second sentence of item A.1.3 of Appendix E of the OL is inconsistent with the staff's initial evaluation.
Therefore, to conform to our evaluation, A.1.3 is revised to read as noted in the full power amendment (i~e., with the second sentence deleted).
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 sub-mittal of the Program Plan and of the Summary Report. By letter L-83-238 dated April 15, 1983, FP&L indicated the Program Plan and Summary Report schedules are as follows:
- a. The Program Plan will be submitted by June 30, 1983.
0 b. The Summary Report will be submitted by September 30, 1983.
St. Lucie 2 SSER 4 22-1
Conclusion The above schedules have been found reasonable and timely and therefore 0
acceptable to the staff.
I.D.2 Plant Safety Parameter Display Console (SPDS)
Discussion 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 com-pletion of the SPDS and submittal of the SAR and SPDS Implementation Plan. By letter L-83-238 dated April 15, 1983, FP&L indicated the schedules are as follows:
- a. The SPDS will be operable and the operators will be trained by the end of the first refueling outage.
Conclusion The above schedules have been found reasonable and timely and therefore acceptable to the staff.
0 St. Lucie 2 SSER *4 22-2
0 APPENDIX A Continuation of Chronology of Radiological Review March 31, 1983 Generic Letter 83-16A - Transmittal of NUREG-0977 Relative to the ATWS Event at Salem Generating Station, Unit No. 1 April 4, 1983 Board Notification 83 Staff Position Regarding Unresolved Safety Issue A-17.
April 4, 1983 Board Notification 83 Board Notification Regarding the Need for Rapid Primary System Depressurization Capability in PWR I s.
- April 6, 1983 Issuance of Facility Operating License NPF-16 authorizing fuel loading and 5% power operation.
April 6, 1983 Letter from licensee regarding continuous containment purge system.
April 6, 1983 Letter from licensee regarding its Regulatory Guide 1.63 commitment.
April 6, 1093 Letter from licensee regarding emergency operating procedures.
April 8, 1983 Generic Letter 83 Integrity of the Requalification Examinations for Renewal of Reactor Operator and Senior Reactor Operator Licenses.
April 13, 1983 Letter from licensee forwarding "process control program,"
Revision 1.
April 14, 1983 Letter from licensee regarding use of flame impingement shields inside containment.
April 14, 1983 Letter to licensee advising of upcoming visit on security matters.
April 14, 1983 Letter to licensee regarding method employed in performing validation of LASL vital area analysis.
April 15, 1983 Letter from licensee in response to Generic Letter 82-33 regarding emergency response capabilities.
April 18, 1983 Letter from licensee in response to Generic Letter 83-lOb regarding resolution of TMI Action Plan II.K.3.5, "Automatic Trip of Re~ctor Coolant Pumps. 11
(:> April 19-22, 1983 Site visit on physical security matters.
St. Lucie 2 SSER 4 A-1
April 19, 1983 Letter from licensee requesting Technical Specification amendment to modify surveillance requirements of pressurizer 0
associated with reactor coolant system.
April 20, 1983 Letter from licensee requesting Technical Specification changes on steam generator pressure/temperature limitation and neutron flux monitor surveillance.
April 20, 1983 Letter to* licensee transmitting Supplement No. 3 to SER.
April 21, 1983 Letter from licensee regarding nuclear plant .records.
April 22, 1983 Letter from licensee forwarding safeguards information.
April 22, 1983 Issuance of Amendment No. 1 to NPE-16 regarding neutron flux monitor surveillance requirements.
May 2, 1983 Generic Letter 83 New Procedures for Providing Public Notice Concerning Issuance of Amendments to Operating Licenses.
May 4, 1983 Board Notification 83 Differing Professional Opinion Regarding Systems Interaction and Safety Classification.
May 9, 1983 Generic Letter 83 Integrated Scheduling for Implementa-tion of Plant Modifications.
May 10, 1983 Letter to licensee advising of acceptability of process con-trol program.
May 10, 1983 Letter from licensee regarding license condition on continuous containment purge/hydrogen purge system.
May 11, 1983 Letter from licensee advising that it has satisfied commitments on security matters.
May 11, 1983 Generic Letter 83 Clarifictaion of Access Control Proce-dures for Law Enforcement Visits.
May 11, 1983 Letter from licensee (to Region) transmitting revised Chapters 5 and 6 to security plan.
May 14, 1983 Letter from licensee forwarding information on Engineered Safety Features Actuation System.
May 20, 1983 Letter from licensee confirming that GE AK-2 scram breakers used at St. Lucie 2.
May 25, 1983 Letter from licensee transmitting information concerning tur-bine trip upon reactor trip.
May 25, 1983 Letter from licensee transmitting summary of-calculations performed to determine flood level inside containment.
0 St. Lucie 2 SSER 4 A-2
0 May 25, 1983 Letter from licensee forwarding information on remote shut-down demonstration.
May 25, 1983 Letter from licensee forwarding information on security system.
May 26, 1983 Letter from licensee transmitting information to document resolution of items required to be complete prior to initial criticality.
May 27, 1983 Letter from licensee providing information regarding loss of all AC power test program.
May 31, 1983 Letter to licensee transmitting draft technical evaluation report on submittal regarding control of heavy loads.
May 31, 1983 Letter from licensee forwarding justification for interim operation regarding qualification of CONAX assembly used in inadequate core cooling instrumentation.
0 St. Lucie 2 SSER 4 A-3
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0 APPENDIX B PRINCIPAL CONTRIBUTORS V. Nerses Project Management J. Lee Project Management J. Kennedy Environmental Qualification C. Li Containment Systems R. Skelton Security W. Long Procedures and Test Review W. Kennedy Procedures and Test Review C. Liang Reactor Systems 0
St. Lucie 2 SSER 4 B-1
0 NRC FORM 335 1. REPORT NUMBER (Assigned by DOC)
U.S. NUCLEAR REGULATORY COMMISSION (7-77)
NUREG-0043 BIBLIOGRAPHIC DATA SHEET Sunnlement No. 4
- 4. TITLE AND SUBTITLE (Add Volume No., if appropriate) 2. (Leave blank)
Safety Evaluation Report Related to the Operation of
- 3. RECIPIENT'S ACCESSION NO.
St. lucie Plant, Unit No. 2
- 7. AUTHOR IS) 5. DATE REPORT COMPLETED MONTH I YEAR June 1983
- 9. PERFORMING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code) DATE REPORT ISSUED Division of licensing MONTH I YEAR June 1983 Office of Nuclear Reactor Regulation u.s. Nuclear Regulatory Commission 6. (Leave blank)
Washington, D.C. 20555 8. (Leave blank)
- 12. SPONSORING ORGANIZATION NAME AND MAI LING ADDRESS (Include Zip Code)
- 10. PROJECT/TASK/WORK UNIT NO.
Same as 9. above 11. CONTRACT NO.
- 13. TYPE OF REPORT I PERIOD COVERED (Inclusive dates)
- 15. SUPPLEMENTARY NOTES 14. (Leave blank)
Docket No. 50-389
- 16. ABSTRACT (200 words or less)
Supplement No. 4 ~o the Safety Evaluation Report for the application filed by Florida Power & Iifht Company, et al for a license to operate the St. Incie 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 Cormnission. The purpose of this supplement is to update the Safety Evaluation Report by providing (1) the staff evaluation of additional information submitted by the licensees since Supplement No. 3 to the Safety Evaluation Report was issued and (2) the results of the evaluation of matters the staff had under review when the previous supplements were issued.
- 17. KEV WORDS AND DOCUMENT ANALYSIS 17a. DESCRIPTORS 17b. IDENTIFIERS/OPEN-ENDED TERMS 0 18. AVAILABILITY STATEMENT Unlimited
- 19. SECURITY CLASS (This report)
TTTl~, ~ ssified
- 20. SECURITY CLASS (This page) lTnc 1 <> RSified
- 21. NO. OF PAGES
- 22. PRICE NRC FORM 335 (7-77)
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UNITED STATES FIRST CLASS MAIL NUCLEAR REGULATORY COMMISSION POSTAGE & FEES PAID USNRC WASHINGTON, D.C. 20555 WASH O C ,'
PE RIIIT No li1. I
- J OFFICIAL BUSINESS PENALTY FOR PRIVATE USE. $300