ML20055B280
| ML20055B280 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 06/30/1982 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-0712, NUREG-0712-S06, NUREG-712, NUREG-712-S6, NUDOCS 8207210141 | |
| Download: ML20055B280 (69) | |
Text
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NUREG-0712 Supplement No. 6 t Safety Evaluation Report f related to the operation of San Onofre Nuclear Generating Station, Units 2 and 3 i
Docket Nos. 50-361 and 50-362 1
Southern California Edison Company, et al.
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CommissionU.S. Nuclear Regulatory f
Office of Nuclear Reactor Regulation l
June 1982 I
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NOTICE Availability of Reference Materials Cited in NRC Publications Most documents cited in N RC publications will be available from one of the following sources:
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NUREG-0712 Supplement No. 6 Safety Evaluation Report related to the operation of San Onofre Nuclear Generating Station, Units 2 and 3 Docket Nos. 50-361 and 50-362 Southern California Edison Company, et al.
U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation June 1982 p>= = = n,,
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TABLE OF CONTENTS 4
PAGE 1
INTRODUCTION AND GENERAL DISCUSSION..........................
1-1 1.1 Introduction............................................
1-1 1.7 Summa ry o f Outs ta nd i ng I s s ue s..........................
1-1 3
DESIGN CRITERIA-STRUCTURES, COMPONENTS, EQUIPMENT AND SYSTEMS....................................................
3-1 3.7 Seismic Design..........................................
3-1 3.7.4 Sei sn.ic Design Veri fication Program..............
3-1 5
REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS.................
5-1 5.3 Reactor Vesse1..........................................
5-1 5.3.3 Reactor Vessel Integrity.........................
5-1 5.4 Component and Subsystem Design.....................
5-1 5.4.3 Shutdown Cooling System..........................
5-1 13 CONDUCT OF OPERATIONS........................................
13-1 13.3 Emergency Preparedness Evaluation.....................
13-1 13.3.4 Evaluation of State and Local Plans...........
13-1 14 INITIAL TEST PROGRAM........
14-1 17 QUALITY ASSURANCE.....................................
17-1 17.3 Quality Assurance Program...............................
17-1 22 TMI-2 REQUIREMENTS...........................................
22-1 22.2 Discussion of Requirements..............................
22-1 I.G.1 Special Low-Power Testing and Training...........
22-1 San Onofre SSER #6 i
i LIST OF TABLES 4
i 17-1 Updated Regulatory Guidance for Quality Assurance............
17-1 22-1 Operational Criteria.........................................
22-3 1
22-2 Test Termination Criteria...................................,.
22-5 22-3 Summary of Safety Evaluation.................................
22-9 22-4 Events Bounded by FSAR Results...............................
22-11 LIST OF FIGURES 22-1 Fuel Performance and Test Operation Domains in the Reactor Power vs. Vessel Flow Space..........................
22-12 APPENDICES A.
CONTINUATION OF CHRON0 LOGY OF RADIOLOGICAL REVIEW............
A-1 B.
PRINCIPAL NRC STAFF REVIEWERS................................
B-1 C.
UNRESOLVED SAFETY ISSUES.....................................
C-1 D.
BIBLIOGRAPHY.................................................
D-1 t
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San Onofre SSER #6 ii r--,
1 INTRODUCTION AND GENERAL DISCUSSION 1.1 Introduction On February 6, 1981, the Nuclear Regulatory Commission (NRC) staff issued a Safety Evaluation Report (SER) on the San Onofre Nuclear Generating Station Units 2 and 3 (SONGS 2 and 3, or San Onofre 2 and 3). The SER covered all non-TMI-related aspects of our safety review of San Onofre 2 and 3.
On February 25, 1981, the staff issued Supplement No. 1 to the SER which addressed the THI-related aspects of our safety review.
On May 8, 1981, the staff issued Supplement No. 2 to the SER, which addressed a number of the open items identi-fied in the SER and in Supplement No. 1 to the SER.
On September 16, 1981, the staff issued Supplement No. 3 to the SER, in which we updated the status of our review with regard to certain of the items that were left unresolved in Supple-ment No. 2 to the SER.
On January 22, 1982, the staff issued Supplement No. 4 to the SER in which we addressed the open items identified in the SER and previous supplements, as well as several TMI-related items for which the applicants had requsted relief from the dated requirements of NUREG-0737.
On February 16, 1982, we issued Supplement No. 5 to the SER, which addressed several items that had arisen since the previous supplement was issued, includ-ing an additional applicant request for relief from certain dated requirements of NUREG-0737.
Also, on February 16, 1982, operating license NPF-10 was issued for San Onofre Unit 2, authorizing fuel loading and low power testing not to exceed five percent of full rated power.
In this supplement to the SER we address several items that have been updated since the previous supplement was issued, as well as items that have recently come to light.
The items addressed in this report are covered in sections having the same number and title as the section of the SER or SER Supplement in which they were previously discussed.
Appendix A to this report is a continuation of the chronology of the radiological review of San Onofre 2 and 3.
Appendix B is a list of the principal NRC staff reviewers who contributed to this supplement.
Appendix C is a discussion of additional Unresolved Safety Issues (ACRS Generic Concerns) that have been developed since the SER was issued.
Appendix D is a bibliography.
The NRC project manager for San Onofre 2 and 3 is Mr. Harry Rood.
Mr. Rood may be contacted by writing to the Division of Licensing, U.S. Nuclear Regulatory Commission, Washington, D.C., 20555.
1.7 Summary of Outstanding Issues In its Initial Decision of May 14, 1982 and its clarifying Order of May 25, 1982, the Atomic Safety and Licensing Board authorized issuance of an amendment to the San Onofre Unit 2 operating license permitting operation at full power.
The Board's Decision was subject to several conditions relating to emergency preparedness.
These conditions are discussed in more detail in Section 13.3.4 San Onofre SSER #6 1-1
of this report.
At this time, certain of the Board's conditions represent the only outstanding items that must be satisfied prior to San Onofre 2 being authorized to exceed five percent power.
The staff plans to confirm that these items have been carried out in the manner specified by the Board.
San Onofre SSER #6 1-2
3 DESIGN CRITERIA - STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS 3.7 Seismic Design 3.7.4 Seismic Design Verification Program The Southern California Edison Company (SCE) contracted with Torrey Pines Technology, a subsidiary of the General Atomic Company (GA), to perform an independent evaluation of the seismic design and quality assurance program for San Onofre 2 and 3.
On January 25, 1982, an interim report was issued by GA.
Our review of the interim report is given in Supplement No. 5 to the SER, dated February 16, 1982.
On April 5, 1982, GA issued a final report. Our review of the final report is given below.
(1)
Introduction On December 3, 1981 the Southern California Edison Company formally noti-fied the NRC that they had retained the General Atomic Company to conduct an independent verification of San Onofre Unit 2 and 3 seismic design.
SCE reported that they took this action to provide greater assurance of the adequacy of San Onofre 2 and 3 design in view of the design problems recently identified at other nuclear facilities.
(2) Background The design verification encompasses a review of the seismic design of San Onofre 2 and 3 to:
verify that the design process converted the seimsic design basis a.
specified in the San Onofre 2 and 3 Final Safety Analysis Report (FSAR) into the design documents that are transmitted to the con-structor or fabricator, and b.
evaluate the SCE quality assurance (QA) audit plan and its implemen-tation at the construction site and the fabricator's shops.
The design process performed by the equipment fabricators is not part of this review program.
The work is divided into eight major tasks:
Task A.
Design Procedure Review Task B.
Design Procedure Implementation Review Task C.
Seismic Design Technical Review Task D.
Audit Plan Review Task E.
Processing of Findings Task F.
Reports Task G.
Pipe Segment Walkdown Task H.
Independent Calculations San Onofre SSER #6 3-1
Tasks A through D, G, and H relate to the actual verification process whereas tasks E and F relate to the administ'ative functions of processing findings and documentation in the interim and final reports.
The review has been structured to concentrate on Unit 2.
It includes Unit 3 only in those areas where there are significant differences between Unit 2 and Unit 3.
Two reports were issued by GA as a result of the review.
On January 25, 1982 the first GA report was issued, entitled " INTERIM REPORT, Independent Verification of San Onofre Nuclear Generating Station Units 2 and 3 Seismic Design and Quality Assurance Program Effectiveness." This report makes reference to 58 " potential findings" generated from the verification activity as of January 25, 1981.
In addition, supporting information was submitted by SCE cover letters of January 29, February 4, February 5, February 11, and February 14, 1982. On January 28 and February 9,1982, meetings between the NRC staff and GA and SCE were held to review the status and significance of the potential findings and other conclusions provided in the January 25, 1981 Interim Report.
The second and final report, entitled, " Independent Verification of San Onofre Nuclear Generat-ing Station Units 2 and 3 Seismic Design and Quality Assurance Program Effectiveness," was issued on April 5, 1982.
Meetings between the staff and GA and SCE were held to discuss the final results of the program on March 16, and April 12, 1982.
The review was conducted by individual GA reviewers investigating each area covered by Tasks A through D, G, and H.
When a reviewer found a deficiency that might have safety significance, it was documented in a
" Potential Finding Report." Potential findings are subdivided into four types:
a.
Technical--Includes use of incorrect calculational techniques, nonconservative assumptions, incorrect input values, numerical errors, invalid conclusions.
b.
Design Definition--Includes inadequate, inconsistent, or imprecise definition of design requirements, incorrect references or inputs.
c.
Traceability--Includes use of undocumented sources of input, unsub-i stantiated conclusions.
d.
Procedural--Includes failing to have or follow adequate procedures.
After the Potential Finding Report (PFR) was written, it was sent to the
" original design organization" that was responsible for the area covered by the PFR.
The original design organization (OD0) then investigated the PFR and responded in writing.
The PFR and the 000 response was then reviewed by a GA committee, and the PFR was classified as (1) Out of scope, (2) Invalid, (3) Observation, or (4) Finding.
Out of scope items are those which are beyond the original scope of the review.
For example, the review was oriented towards design verification.
Procurement items are considered out of scope.
Invalid Findings are the result of apparent deviations, uncovered in the course of the independent San Onofre SSER #6 3-2 1
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verification, that are resolved to the satisfaction of project personnel, usually during the Potential Finding review by the Original Design Organi-zations.
Observations are valid deviations that are judged not to have the potential for significant impact on the seismic design adequacy of San Onofre Units 2 and 3.
Findings are valid deviations that could have potential for significant impact on the seismic design adequacy.
Observations and Findings were sent to the Executive Vice-President of SCE for resolution.
In the case of Findings, a Corrective Action Plan (CAP) was prepared and returned to GA for review.* The review will determine if the CAP satisfies the concern expressed in the Findings.
The final report prepared by GA consists of three volumes:
Volume 1, " Executive Summary" Volume 2, " Program Results" Volume 3, " Potential Finding Reports" Volume 3 consists of Book 1, which includes Potential Finding Reports (PFR) 0001 to 0058 and F001 to F040; and Book 2, which includes Potential Finding Reports F041 to F112 and Corrective Action Plans.
PFR 0001 to 0058 were discussed in the Interim Report and PFR F001 to F112 were identified during the " final Phase" of the program.
On April 12, 1982 a meeting between the staff and GA and SCE was held to review the signifi-cance of the potential findings and conclusions provided in the final report.
Of the total of 170 PFRs that were initiated, 77 were determined to be invalid after additional information was reviewed.
Of the 93 PFRs that were determined to be valid, 7 were classified as findings and 86 as observations.
The numbers of findings and observations for each of the various tasks are as follows:
Task Findings Observations A
3 2
B 1
35 C
1 41 0
2 5
G 0
2 H
0 1
Total 7
86 In addition to the program plan, its execution, and results, the Staff also examined the independence of the contractor performing the design verification (GA) and the quality controls applied to the administration of the design verification activity.
- Although the Program Plan did not require it, SCE has stated that a corrective action plan was prepared for all observations as well as all findings.
San Onofre SSER #6 3-3
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(3)
Independence of the Design Verification Contractor The staff reviewed the independence of the design verification contractor (General Atomic Company).
The objective of the staff review was to deter-mine whether or not the contractor could be expected to provide an objec-tive, dispassionate technical judgment, provided solely on the basis of technical merit.
The following factors were considered in this determin-ation:
a.
The extent of the previous or current involvement of GA and the GA reviewers with Southern California Edison Company or San Diego Gas and Electric Company.
b.
Whether the GA reviewers own or control significant amounts of stock in SCE or SDG&E.
c.
Whether members of the present household of the GA reviewers are employed by SCE and SDG&E.
d.
The administrative controls implemented at GA to assure that an auditable record will be provided of all comments on draft or final reports, any changes made as a result of such comments, and the reasons for such changes; or the consultant will issue only a report without prior SCE comment.
l Correspondence provided by General Atomic and Southern California Edison to the NRC staff demonstrated that recent contracts (within the last two years) between GA and the licensees, Bechtel Power Corporation (BPC), and 1
Combustion Engineering Inc. (CE), account for less than 3% of GA revenue.
The staff considers this value low enough to assure corporate financial independence.
s In reference to the independence of individuals the contractor (GA) has established the following criteria:
)
Key project personnel shall have no present or past work experience a.
in design, construction or quality assurance of the San Onofre Nuclear Generating Station (SONGS) or with Southern California Edison Company (SCE) and San Diego Gas & Electric Company (SDG&E).
b.
Project personnel shall not be active on any other current SONGS, SCE, or SDG&E work.
Project personnel, other tnan the key personnel, shall not have any c.
substantial prict work experience relating directly to SONGS, par-4 ticularly in the areas of quality assurance and structural analysis, d.
No project personnel shall have members of their immediate family (parents, spouse, children and grandchildren) who are employed by SCE or SDG&E or are engaged directly or indirectly in the design or construction of SONGS.
San Onofre SSER #6 3-4 2,
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During the term of this project no projelt personnel and their immediate family shall have cumulative ownership interest in SCE and f
SDG&E which exceeds 5% of the'!r gioss family annual income.
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' The staff concludes that the i;@lementatiorsof these criteria is adequate 4
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to assure sufficient indivioual independence.. The implementation of the criteria was evaluated by a staff review of a cample of the contractor's personnel / security questionnaires and' confidential interviews with a i
selected number of the contractor's uployees in a meeting at the GA offices on January 6-8, 1982.
In a11' cases it was found that the indi-
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viduals' met the independenct friteria established by the contractor.
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' The.staf f examined the contractor (s administrative controls implemented to assure.that auditable records are saintaired for all information related t6 review findings and reports transmitted'between the contractor and the applicants /Bechtel/ Combustion Engineering.
These controls are considered e
g to provide _ adequate assurance that the contractor's independence is not compromised.
In summary, for the, reasons given above, the staff concludes that the selected contractor, GA, has adequately demonstrated both corporate and
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individual independenhe.
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(T) Technical QuitificM ions of the Desiga Verification Contractor Th'e staff also reviewed the technical qualifications of the design verifi-cation contractor (GA).
The objective of the staff review was to deter-mine +hether or n6t-the contractor could be expected to provide the depth i
and scope of technical review neceisary to pr be the significant elements of the seismic design developed for San Onofre 2 and 3 and to develop conclusions as to the adequacy'of that design based on sound engineering principles and practice.
In making this determination, the staff con-1 sidered both the infrastructure of the contractor's organization and the 4
qualifications of the assigned staff.
Trie infrastructure necessary-to asshre coordination and integration of engineering disciplines necessary for the verification program is provided by Torrey Pines Technology, a division of GA.
GA has carried out numerous engineering design projects for major nuclear systems and structures.
These projects have involved designs to meet the requirements of national structural and mechanical engineering codet, as well as NRC regulatory practices.
The GA experience includes the full range of activity neces-s sary for seismic design.
This covers the range from development of mathematical models to characterize structures and components to the
.y detailed design of components and specification of.. test programs for equipment.
The staff concludes that this breadth and depth of experience demonstrates that GA is qualified to conduct the verification program.
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Qualifications of the professional staff assigned to the verification program have been reviewed on the basis of individual resumes and by
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Ine individual resumes show that all the assigned GA staff members hold 3
oogrees.in mechanical and structural engineering; and a majority hold s.
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San Onofre SSER #6 3-5 sA
advanced degrees in the engineering specialties associated with seismic design.
The resumes of the quality assurance personnal show that they have extensive and applicable background and experience.
During the period January 6 through January 8,1982, representatives of the staff and a staff consultant met with SCE and GA to discuss the scope and the progress of the verification program.
Staff engineers and our consultant observed the GA professional staff at work on the verification program.
We discussed with the GA engineers their approach to typical aspects of the program.
This included the methods the GA engineers would use to develop and examine the information they felt would be necessary to reach a conclusion regarding the adequacy of the seismic design (for San Onofre 2 and 3) and the criteria they would apply in reaching those conclusions.
Based on the credentials shown by the resumes and the observations made at GA, the staff concludes that the professional personnel assigned to the verification program have qualifications and expertise adequate to perform their assigned duties.
(5) Quality Assurance Program Implementation for Design Verification Activities The contractor, in its proposal to the licensees, agreed to conduct the design verification in accordance with the NRC approved General Atomic Quality Assurance Program, Topical Report No. GA-A13010A, Amendment 6.
The specific QA controls used in performance of the Design Verification Program (QAPD-2408) were examined by the staff. The staff reviewed the design verification contract documents, program plan, and implementing contractor procedures and determined that these documents provided suffi-cient controls to assure that the design verification would be conducted substantially in accordance with the approved Topical Report.
Implemen-tation of the procedures and other pertinent requirements was examined during a staff visit to the GA offices during the period of January 6 through 8, 1982.
The staff representatives found that, for those areas examined, activities were being performed in accordance with the estab-lished quality and procedural controls.
The staff, therefore, concludes that adequate quality measures have been implemented for the design verification activity.
(6) Task A, " Design Procedure Review" This task involved the determination of whether adequate design control procedures were in place consistent with the QA program commitments given in the PSAR for both the licensee and its contractors, and the require-ments of Appendix B to 10 CFR 50.
QA controls for design given in ANSI N45.2.11 were also utilized as guidance for this review.
Review of the design control procedures resulted in the identification of five valid Potential Finding Reports (PFRs).
All the PFRs were related to CE activities and were classified as two observations (0049, F004) and three findings (0038, 0047, 0052).
In each case, it was determined that there was either a deficiency in an existing procedure or no formal procedure existed at all.
Followup work conducted under other program San Onofre SSER #6 3-6
tasks ultimately confirmed that despite these deficiencies, the required functions were adequately carried out.
The staff concurs with this conclusion.
(7) Task B, " Design Procedure Implementation Review" The objective of this task was to determine if the design control procedures i
in effect at SCE, CE, and Bechtel were properly implemented in the design documents related to seismic design work.
The scope of the task included preparation of detailed procedures, including checklists, to be used by the GA reviewers in the design document review; identification of design documents and governing procedures to be reviewed; and the actual review of the documents.
GA reviewed approximately 1280 documents during this task and documented the effort on the checklists.
The Task B effort resulted in the initiation of 52 PFRs; 16 of which were determined to be invalid and 36 to be valid.
Of the valid Task B PFRs, 35 were classified as observations and one as a finding.
The one finding (PFR F015) resulted from the accumulation of seven valid PFRs that were all based on a lack of strict compliance with SCE design 1
procedures in the design of the auxiliary intake structure.
The auxiliary intake structure was the only seismic safety item designed by SCE.
GA concluded that individually each of the seven PFRs were observations; but collectively, because of their repetititve nature, they were judged a finding.
PFR F015 was used as the PFR for transmitting the finding.
SCE identified corrective action for each of the individual PFRs and wrote a Corrective Action Plan (CAP) for PFR F015.
GA concluded that SCE had provided acceptable corrective action for these seven PFRs.
The staff reviewed the identified corrective action and agrees with the GA conclu-sions.
The finding is not considered a substantial safety issue, because the technical adequacy of the design was demonstrated under Task C, and the corrective action identified by SCE appears to be sufficient.
The 35 Task B PFRs classified as observations generally involved various types of procedural violations, all of which were determined to have no adverse impact on plant safety.
It was concluded under this task that the seismic design activities were performed substantially in accordance with approved procedures.
The staff concurs with this conclusion.
(8) Task C, " Seismic Design Technical Review The objective of this task was to review the seismic design of selected safety-related structures, systems, and components for compliance with the design bases and methodology-contained in the FSAR for San Onofre 2 and 3.
A general description of the task is given in " Program Plan - Independent Verification of SONGS 2 and 3 Seismic Design," December 1981, by Torrey Pines Technology, a Division of General Atomic Company (GA).
Staff review of initial activities under this task was reported in Supplement No. 5 to the Safety Evaluation Report.
The staff review at that time was based on the interim report and meetings held at the GA facilities in La Jolla, California on January 6 through 8, 1982 and meetings in Bethesda, Maryland on January 28 and February 9, 1982.
San Onofre SSER #6 3-7
Since publication of Supplement No. 5 to the Safety Evaluation Report, GA has completed its review of the following additional features selected in accord with the overall independent verification program.
- Reactor containment building
- Auxiliary intake structure
- Dynamic analysis of reactor coolant system
- Reactor coolant pump and supports
- Reactor vessel support
- Fuel element grid spacers
- Reactor coolant system cold leg (piping)
- Diesel generator oil storage tank
- Two locally mounted instruments
- Cable raceways
- Control panel CR57
- Segment of reactor containment building internal structure and supported equipment.
The GA review of major structures (the reactor containment building and the auxiliary intake structure) included all dynamic analyses necessary to show reasonableness of in-structure response spectra used for seismic design of components and systems located in the reactor containment building.
Structural design of several component and equipment supports were also reviewed to verify that imposed loadings and responses were correctly reflected in the structural design.
The GA review of the Safety Injection System (SIS) included the piping from the refueling water storage tank to the nozzle in cold leg loop 1A of the NSSS piping, and small-bore piping (1-inch lines for safety injection tank T-008 and 1-and 2-inch lines between the major piping in the vicini-ty of the tank).
All valves on this segment of the SIS system, and motor operators where they occurred, were included in the review as were the two tanks and the LPSI pump.
All 11 power control panels associated within this segment of the system were reviewed.
All major instruments and some sub-tier instruments, including electrical cables associated with this segment of the SIS system, were also reviewed.
Selected pipe supports and snubbers, equipment support, and cable tray supports within the SIS segment were reviewed for seismic design adequacy.
The staff discussed the PFRs developed during this portion of the program with representatives of GA and SCE at meetings held in Bethesda, Maryland on March 16 and April 12, 1982. During the course of these meetings PFRs of particular interest to the staff were discussed in light of:
a.
Clarity of the problem statement.
b.
Quality and technical depth of the response by the 000.
c.
Accuracy and appropriateness of the contractor's Impact Assessment.
d.
Basis and appropriateness of the contractor's disposition.
One finding and 42 observations resulted from Task C.
The finding (PFR 0009) pertains to the design adequacy of several diagonal braces that connect cable tray supports to concrete slabs.
San Onofre SSER #6 3-8
f f
The primary concern was that the diagonal pullout design loads imposed on the concrete inserts excceded allowable limits.
In addition, the diagonal braces were designed to be installed at an angle of 45, while the instal-lation drawings allow these braces to be installed at 30, 45, and 60 angles.
A field inspection revealed that the specific brace in question was installed at an angle of 67.3, causing the vertical load component to r
be dominant.
GA also felt that the concrete insert pullout allowable values taken from the design catalog employed should be discounted to account for the limited data base upon which the allowable values were 4
derived.
A Corrective Action Plan has been approved by the licensee to resolve this finding.
This plan involves (1) a review of calculation packages to establish that proper methodology and procedures was used for design of bracing for all cable tray supports in San Onofre 2 and 3, (2) calculation of maximum bracing angles for certain braces (actual maximum cable tray loadings may be employed rather than conservative design values), (3) use of qualified capacity reduction factors for connections, where the load I
capability data are referenced to a limited data base, and (4) a field inspection sampling to verify that bracing angles and member sizes are consistent with calculations and drawings.
The staff concurs that this corrective action is appropriate and adequately addresses the finding.
e As a result of the review of major piping performed under Task C, a possible trend was identified which suggested incomplete analysis of Unit 3 piping in areas where it was not identical to or the mirror image of Unit 2 piping.
The licensee states that two independent checks were employed to assure that all unique Unit 3 piping was analyzed.
First, all design documents were reviewed to tabulate the Unit 3 piping runs that l
were not identical or mirror images of Unit 2.
GA has reviewed this l
tabulation (prepared prior to this program) and has concluded that the piping runs associated with the trend are included in the tabulation.
The second check will be a comprehensive as-built verification program.
The staff concurs that these actions are an appropriate response to the possible trend identified by GA.
Based on our review, the staff concludes that Task C was performed in accordance with the approved design verification program and that this activity provides additional assurance that the seismic design for San Onofre 2 and 3 was conducted in accord with acceptable practices.
(9) Task D " Audit Plan Review" The objective of this task was to review and evaluate the QA audit plans of the licensee and Bechtel Power Corporation (BPC), and to verify implemen-tation of those plans.
The review and evaluation has been restricted to l
audit plans and audits covering implementation of seismic design output (i.e., drawings and specifications) at the construction site or the i
fabricator's shops.
The scope of this task included GA review of (a) SCE and BPC procedures for audit planning and scheduling, (b) the use of those procedures by SCE and BPC to prepare audit plans and schedules, and (c) audit plan implementation by SCE and BPC.
San Onofre SSER #6 3-9 i
GA concluded that SCE and BPC procedures for audit planning and scheduling were consistent with regulatory requirements, except for the lack of a licensee procedural requirement in response to one part of the regulatory requirements.
This item was classified as a finding (PFR 0034) and states that one licensee audit procedure did not specify "assessement of effectiveness of the quality assurance program" as an audit objective.
In response to this finding, the licensee established that the SCE QA Manual for Units 2 and 3 specifies that audits are used to verify overall effectiveness of the QA program, and identifies how audits as well as other management controls are used to assess the effectiveness of the QA program.
The staff concludes that licensee audits, as well as other controls, have been used to assess the effectiveness of the QA program even though the one SCE procedure does not specifically indicate "assesssment of effectiveness" as an audit objective.
The finding is not considered to be a substantial quality or safety issue.
GA concluded the SCE and BPC audit schedules and plans were prepared in accordance with the procedural requirements.
No PFRs were initiated.
The GA review of audit plan implementation resulted in 16 PFRs being initiated, of which ten were judged to be invalid.
Of the six valid PFRs, five were classified as observations and one as a finding.
The one finding (PFR F051) resulted from BPC not maintaining a permanent record of audit nonconformances classified as " minor." SCE's Corrective Action Plan (CAP) provided information which showed that all nonconformances identified on BPC audit checklists were in fact maintained in the SCE permanent record system.
GA concluded that the PFR would not have been classified as a finding if the information in the CAP had been known at the time of PFR classification.
The staff agrees with GA's conclusion based on review of PFR F051 and the resulting CAP.
The five Task D PFRs classified as observations were reviewed by the staff.
The staff agrees with the GA decision to classify these PFRs as observations because they do not appear to have an adverse l
impact on plant safety.
In addition, the staf f examined the contractor's activity related to this task during a visit to the contractor's facilities on January 6 through 8, 1982 and during a meeting on January 28, 1982.
Based upon the review, the staff concludes that the contractor's activity on this task was performed in accordance with the program plan and that this activity provides additional assurance that the licensee's and BPC's audit program was properly implemented.
(10) Task E, " Processing of Findings" This is an administrative task and was not reviewed by the staff.
A discussion of this area is given above, under (2) Background.
(11) Task F " Reports" This is an administrative task and was not reviewed by the staff.
(12) Task G, " Pipe Segment Walkdown" The objective of this task was to verify by visual examination the proper installation of portions of a particular piping run that was reviewed in San Onofre SSER #6 3-10
Task C.
This task was completed and the results reviewed by GA at the time of the interim report.
In Supplement No. 5 to the safety evaluation the staff concluded that Task G was being carried out in accord with the program plan and that this effort provides additional assurance that the installation of piping systems was consistent with the design analyses for San Onofre Unit 2.
There has been no change to this conclusion since Supplement No. 5 was issued.
(13) Task H, " Independent Calculations" The objective of Task H was to perform independent calculations using alternate analytical techniques on selected features of San Onofre 2 and 3.
Results were compared with original calculations for consistency.
The features selected to be independently analyzed were the low pressure safety injection pump support mount and the safety injection tank.
Both of these features are subject to seismic loads that are a significant I
fraction of total loads and have relatively low design margin.
GA performed a modal analysis of the support mount for a low pressure safety injection pump using the computer program MODSAP.
The computer frequencies were compared with the original design basis calculations.
Significant differences between the response frequencies calculated by GA and calculated by the original analysis were determined to exist.
Never-1 theless, GA concluded that the required design goal, i.e.,
that the pump-support system be rigid, was accomplished.
The fact that the pump-support system was rigid resulted in insignificant changes in stress levels due to the differences in calculated frequency.
A seismic analysis of the safety injection tank was also performed using the M0DSAP computer program.
The bending frequency calculated by GA agreed well with the original design calculation.
Minor differences, due to modeling, were seen in vertical frequency.
The effects of seismic restraint-to-floor displacements were consistent with the original analy-sis for both the OBE and SSE conditions.
In the great majority of instances the maximum forces, loads and moments acting on the tank supports were larger in the original analysis than in the GA analysis.
I The methodology employed by GA to calculate buckling loads due to liquid sloshing resulted in calculated stresses at the skirt supporting the tank that were in excess of those calculated in the design analysis.
GA concluded that the overall effect on the function of the tank was neg-ligible and that the tank design was adequate.
The staff has reviewed the analytical approach employed by GA and con-cludes that this approach was appropriate for the intended purpose.
The numerical results of the GA calculations differed significantly from the original analyses in some instances.
However, GA has concluded that the results of Task H tend to confirm the broader conclusions developed throughout the independent review program, i.e., that the extensive experience of the design staff coupled with the large degree of conser-vatism in essentially every aspect of the design and the satisfactory t
results of numerous other check calculations performed in other tasks provides high assurance that fundamental design goals were achieved J
San Onofre SSER #6 3-11
_Jpite such deviations.
The staff believes that this conclusion is i
I reasonable.
(14) Conclusions Regarding Design Verification Program On the basis of the staff review described above, we conclude that the contractor, GA, is acceptably independent, has an acceptable degree of technical qualifications, and has implemented an acceptable QA program for the conduct of the design verification program.
The staff also concludes that the design verification program was acceptably designed and imple-mented to uncover systematic design deficiencies that may exist in the seismic design of San Onofre 2 and 3.
The staff review of the results of the design verification program leads i
us to conclude that the GA design verification program has not discovered anything that would cause us to change our previous conclusions that the San Onofre 2 and 3 quality assurance and seismic design are acceptable, and provides additional assurance that plant design and construction have been appropriately accomplished.
This result provides additional support for granting authority to operate the facility at power levels up to full rated power.
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i San Onofre SSER #6 3-12
l 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.3 Reactor Vessel 5.3.3 Reactor Vessel Integrity Pressurized thermal shock, as a consequence of certain postulated accident scenarios, is an issue of concern primarily for vessels that have experienced significant degradation of material properties due to irradiation damage in the beltline region during operation.
The staff's Unresolved Safety Issue (USI)
Task A-49 will address this issue for all PWR facilities but initially it is concerned primarily with operating facilities.
See Appendix C to this report.
The rate of degradation of material properties is related to the concentration of trace elements in the vessel materials, especially copper, nickel and phos-phorus.
The phenomenon of radiation damage versus accumulated fluence is accounted for in Regulatory Guide 1.99, which is used by the staff to conser-vatively predict material property degradation until sufficient data from irradiation specimens are accumulated for a particular vessel.
The San Onofre 2 and 3 reactor vessels have a predicted end-of-life RT at NDT the inside wall of about 150 F and 120 F, respectively.
This was calculated for the limiting material in the reactor vessel beltline.
For San Onofre 2 the limiting material is the intermediate shell plate C-6404-2, which has 0.10 percent copper, 0.010 percent phosphorus, 0.58 percent nickel, and an initial RT f 16*F.
For San Onofre 3, the limiting material is the intermediate NDT shell plate C-6802-1, which has 0.05 percent copper, 0.008 percent phosphorus, 0.57 percent nickel, and an initial RT f 40 F.
The end-of-life fluence at NDT the inside wall of the reactor vessel is predicted to be 3.68 x 1019 n/cm2 (E)MeV).
Regulatory Guide 1.99 Revision 1 was used to estimate the adjustment of the reference temperature.
Hence, the end-of-life RT values of 150 F and NDT 120 F are believed to be conservative.
The staff believes that the San Onofre 2 and 3 reactor vessels will not be jeopardized by pressurized thermal shock for 32 effective full power years because of the relatively low end-of-life RT However, the staff is NDT.
continuing to study this issue as USI Task A-49 and, if necessary, may reevaluate this conclusion during the next few years.
5.4 Component and Subsystem Design 5.4.3 Shutdown Cooling System In a letter to Chairman Palladino dated December 15, 1981, the Advisory Com-mittee for Reactor Safeguards (ACRS) requested that the staff give considera-tion to the potential for adding valves sized to facilitate rapid depressuri-zation of the CESSAR primary coolant system to allow more direct methods of decay heat removal.
Since San Onofre 2 and 3 also utilize Combustion Engi-neering (CE) Nuclear Steam Supply Systems (NSSS) without power operated relief San Onofre SSER #6 5-1
valves (PORVs), the issue raised by the ACRS is also applicable to San Onofre 2 and 3.
In the San Onofre 2 and 3 NSSS, as with CESSAR plants, decay heat removal capability ultimately relies on heat removal via steam generators using emergency feedwater and atmospheric steam dump valves.
The auxiliary feedwater systems for San Onofre 2 and 3 have been reviewed by the staff and found to meet the reliability criterion of Section 10.4.9 of the Standard Review Plan (NUREG-0800).
Because of this, the staff had previously concluded that the addition of a rapid depressurization capability was not required to achieve a " feed and bleed" mode of decay heat removal as a result of loss of auxiliary feedwater.
However, the ACRS letter and the recent steam generator tube rupture event at Ginna have led the staff to reexamine the reliability of steam generator integrity for decay heat removal over the life of the plant.
In particular, the staff is considering the need for a rapid depressurizatics capability in the event of tube failures in both steam gener-ators.
In addition, the staff is looking at the benefits of providing this capability to afford the operator greater flexibility to respond to unforeseen events (e.g., ATWS).
The staff has requested that information be provided by CE as to the need for a rapid depressurization capability in the CE System 80 (CESSAR) design.
CE has provided an initial response (letter from A. E. Scherer to D. G. Eisenhut dated March 4, 1982) which asserts that the CE System 80 design is adequate without this capability, and suggests that any plant design modifications might more appropriately be directed to providing a rapid depres-surization capability for the secondary system and utilizing additional water sources for feeding the steam generators.
The staff has reviewed CE's response and has requested additional information from CE (letter from R. L. Tedesco to A. E. Scherer dated March 26, 1982), as well as from the San Onofre 2 and 3 licensees (letter from F. J. Miraglia to R. Dietch and D. Gilman dated March 27, 1982).
By letter dated April 30, 1982, Southern California Edison (SCE) responded to the staff request for additional information.
The SCE letter indicated that the detailed answers to all the staff questions were being addressed by the CE Owners Group, and would be provided to the staff as soon as they were avail-able.
In the interim, SCE provided a justification for operation of San Onofre 2 and 3 at full power prior to staff review of the owner's group response.
Specifically the SCE letter of April 30, 1982 provided a report which asserted the following:
(1) The San Onofre Units 2 and 3 NSSS's are coupled with a highly reliable, safety grade auxiliary feedwater system (AFWS).
The AFWS design for San Onofre Units 2 and 3 exhibits a higher level of reliability than most other AFWS designs.
(2) San Onofre Units 2 and 3 are capable of achieving cold shutdown conditions using only safety grade systems, even without offsite power and with an additional single failure.
(3) The San Onofre Units 2 and 3 steam generator design includes many features which will enhance tube integrity, minimizing concerns associated with operating reactors.
Additionally, careful attention to the plant water chemistry program will ensure that the magnitude of the impurity ingress into the steam generators is maintained at a low level.
Becausa of the steam generator water chemistry program and design features which minimize l
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San Onofre SSER #6 5-2
steam generator tube corrosion and stress, SCE considers that steam generator tube degradation should not be a concern during the period the NRC questions are being addressed.
(4) Even if all auxiliary feedwater supply were somehow lost, heat removal could still be achieved by depressurizing the steam generators to allow the use of low head pumps (e.g., firewater or condensate pumps).
(5) Review of probabilistic analyses conducted by the NRC do not show any justification for the addition of reactor coolant system (RCS) valves for decay heat removal purposes.
SCE also stated that it considers that the report adequately responds to the NRC's request for information to justify full power operation of San Onofre Unit 2 without PORVs in the interim, until the issue of the adequacy of rapid depressurization and decay heat removal capability for the existing San Onofre Units 2 and 3 design is resolved.
The staff has reviewed the SCE report and concludes that it provides an accept-able basis for interim operation prior to staff review and approval of the CE Owner's Group submittal.
The staff conclusion is based on the following:
(1) The auxiliary feedwater system (AFWS), which is documented in the San Onofre Units 2 and 3 FSAR, has been modified and upgraded following the post-TMI review in 1981.
The current AFW design includes three full capacity safety grade auxiliary feedwater pumps.
Two motor driven AFW pumps are powered from separate emergency power supplies and one turbine driven AFW pump is designed such that it can deliver AFW to either steam generator under the postulated complete loss of AC power conditions.
The AFW system is designed to seismic Category I, electrical class IE and ASME code class 2 and 3 requirements.
The staff has reviewed the AFW system and concluded that it meets Branch Technical Position ASB 10-1 and the system will have a high degree of reliability.
(2) The capability to achieve cold shutdown for San Onofre 2 and 3 has been reviewed and meets Branch Technical Position RSB 5-1.
During normal shutdown, the same systems used for power generation will be used for plant cooldown.
RCS heat removal is handled via steam generators using main feedwater and steam bypass to the condenser.
RCS pressure is also maintained with the pressurizer, using the normal heater and spray control systems.
In the event that the main condenser or associated systems are unavailable, st.eam will be rejected directly to atmosphere via either of the two safety grade steam generator atmospheric dump valves located upstream of the MSIVs by operator's remote manual action from the control room for plant cooldown.
Makeup water to the steam generators is supplied from either the main feedwater system or the safety grade AFWS.
System design and component elevations of San Onofre Units 2 and 3 are such that natural circulation for decay heat removal is obtained as a result of density differences between the bottom of the core and the top of the steam generator tube sheet, an elevation head of approximately 25 feet.
Natural circulation plant performance will be tested during the startup period of San Onofre Unit 2.
Additionally, several systems design features have been incorporated to assure the maintenance of natural circulation flow.
A redundant pressurizer heater capacity of 150 KW from each diesel San Onofre SSER #6 5-3
generator is available to maintain system subcooling.
When in natural circulation, the safety grade auxiliary spray from the charging system which is also safety grade provides for RCS depressurization.
San Onofre Units 2 and 3 can be brought to the shutdown cooling system initiation point using only safety grade equipment, assuming the most limiting single failure, dnd only onsite or only offsite power available.
(3) A number of improvements in the San Onofre 2 and 3, 3410 MWt steam generators have been incorporated which should assure improved operational reliability and mitigate the operating problems which have been experienced with U-tube steam generators of the recirculation type.
The following modifications are expected to improve the thermal-hydraulic characteristics on the secondary side, a.
The vertical tube spacer strips have been separated from the diagonal
" bat wing" tube supports, b.
The " bat wing" supports have been lowered to avoid intersecting the tube bends.
c.
The tube supports in the small radius bend region have been located below the bends.
d.
The vertical tube spacer strips are now provided with "punchouts" to enhance cross flow freedom, e.
The former drilled upper tube support plates have been replaced with partial "eggcrate" type supports.
Thus, all tube supports are of the "eggcrate" or lattice type to promote freedom of vertical as well as cross flow.
Residual tube stress is minimized by having a large bending radius for the inner tube rows and using improved bending techniques which introduce much lower residual tube stress.
An explosive technique for placing the tubes in contact with the tubesheet for the full tubesheet thickness has been used.
This eliminates the tube-to-tubesheet crevice which has caused corrosion problems in this region, such as stress cracking and intergranular attack.
The elimination of the drilled upper tube support plates is likely to mitigate the denting problems previously experienced in this region.
Tubesheet clad separation and tube damage has occurred in non-CE units due to differential motion between the tubesheet and primary head.
CE has utilized a mechanical joint between the primary head divider plate and its juncture with the tubesheet and primary head to essentially eliminate differential growth and deflection between these members.
The 3410 MWt design utilizes large top discharge elbows for the main /
auxiliary feedwater inlet sparger.
In addition the drain time of this sparger ring has been increased by a sealing device located between the sparger and the feedwater inlet nozzle.
Thus water hammer potential with possible feedwater line damage is reduced.
San Onofre SSER #6 5-4
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San Onofre 2 and 3 have employed a chemistry control program to assure that secondary water chemistry is maintained within appropriate control bounds during operation and that timely corrective actions are taken in the event abnormal chemistry occurs.
An all volatile treatment water chemistry program is utilized for the secondary system.
This method of control precludes tube corrosion and related problems due to the chemical additives, and it minimizes the amount of sludge deposited within the steam generator.
By the above chemistry control program, chemistry related challenges to the integrity of the steam generator tubes are minimized.
(4) In the event of a total loss of all auxiliary feedwater supply, the applicant asserts that heat removal could still be achieved by depres-surizing the steam generators to allow the use of low head pumps in the plant. We have evaluated the availability of the low head pumps which could be used for this purpose.
Since the fire pumps are designed with very low head (shutoff head of 335 feet), they are not practical for feeding steam generators during plant cooldown.
However, the condensate pumps are designed with the pump flow capacity of 7,750 GPM at a discharge pressure of 500 psia.
These pumps can be used to feed the steam generators after they have been depressurized.
We will require SCE to develop proper operating procedures for this plant operation mode.
(5) The staff performed a simplified and limited probabilistic study, using Palo Verde as a base, on the core melt probability for the loss of main feedwater events (including loss of offsite power with emergency power available).
The core melt probability is estimated to be 10 5 per reactor year using an AFW system unreliability (7 x 10 5 per demand) based on the NUREG-0635 methodology.
The core melt probability (10 5/RY) is similar to the contribution for such events stated in WASH-1400.
Therefore, the staff does not believe these results support a need for feed and bleed capability in CE plants without PORVs, provided the AFW unreliability lies in the range of 10 4 to 10 5 per demand and procedures for restoring main feedwater for decay heat removal are available.
The San Onofre AFW system has achieved this range of reliability with the addition of the third AFW pump.
Any future PORV requirements will be determined pending the staff review of the CE owner's group response to our information request (letter from R. L. Tedesco to A. E. Scherer dated March 26, 1982).
In addition, the staff has briefed the ACRS Subcommittee on Decay Heat Removal Requirements (on March 16, 1982) and the full ACRS in an executive session (on April 2, 1982) on the status of the staff's evaluation of this matter.
Subse-quently, the ACRS issued a letter dated April 3, 1982 which stated that while evaluation should be conducted expeditiously, its resolution should not now be a condition for operation of CE System 80 plants at full power or of plants having similar features.
In addition, the letter stated that the need for future hardware or procedural changes should be contingent upon the results of this evaluation.
Should the NRC decide that design or procedural changes are necessary, SCE will be required to implement them for San Onofre 2 and 3.
San Onofre SSER #6 5-5
13 CONDUCT OF OPERATIONS 13.3 Emergency Preparedness Evaluation 13.3.4 Evaluation of State and Local Plans NRC staff witnesses testified on the status of the licensee's emergency pre-paredness during the public hearing in August 1981.
That testimony constitutes the NRC staff's evaluation report on the status of the licensee's state of emergency preparedness at that time.
During the period October 26 through November 6, 1981, an onsite appraisal was conducted by an NRC appraisal team, l
and a followup inspection was made on January 26-28, 1982.
The findings of the appraisal and followup inspection affirm the NRC staff conclusion that an adequate state of onsite preparedness exists at San Onofre 2 and 3.
By letter dated December 1, 1981 (Richard W. Krimm, FEMA to Brian Grimes, NRC),
FEMA provided an updated evaluation of the adequacy of plans and the implemen-tation capabilities of State and local governments related to San Onofre 2 and 3 and concluded that there is a reasonable assurance of offsite emergency response capability provided certain corrective actions (which were previously identified during the hearings on this matter) are completed.
The NRC staff has reviewed this letter and supporting documents and concludes that there is reasonable assurance of onsite and offsite capability to respond to an emer-gency at the San Onofre Nuclear Generating Station.
On May 14, 1982, the San Onofre 2 and 3 Atomic Safety and Licensing Board (the l
ASLB or Board) issued its Initial Decision on the facility.
The principal issue covered in the decision was emergency preparedness (the Board's Partial Initial Decision of January 11, 1982 covered seismic issues).
In its May 14, 1982 Decision, the Board decided the emergency planning issues largely in the licensee's favor, and authorized the NRC staff to issue full power licenses for San Onofre 2 and 3, subject to certain conditions.
The conditions relate to certain deficiencies the Board found in emergency planning for San Onofre.
The Board stated that if these deficiencies were corrected prior to or during the initial phase of full power operations, they would not pose a danger to public health and safety.
The Board retained jurisdiction over an issue concerning arrangements for medical services, in order to review and determine the adequacy of remedial actions that the licensee was directed to take in that area.
The Board also retained jurisdiction over the issue of whether or not the siren system within the City of San Clemente was adequate.
This latter concern was resolved in the Board's Order of June 16, 1982.
The Board found that the siren system in San Clemente is adequate, subject to staff confirmation called for in the Board's condition Al set forth below.
The following is a summary of the conditions imposed by the Board in its Initial Decision of May 14, 1982, as modified by its clarifying Order of May 25, 1982.
San Onofre SSER 6 13-1
A.
Prior to full power operation of San Onofre Unit 2:
1.
The NRC staff shall certify to the ASLB that the siren system has been shown to perform in accordance with its technical specifica-tions.
2.
The NRC staff shall confirm that:
a.
The FEMA concerns expressed in the November Update Evaluation about lesson plans and schedules have been satisfied.
b.
Initial training of adequate numbers of onsite and offsite personnel in each category listed in Section 11.0.4 of NUREG-0654 has been completed, except for radiological monitoring teams and radiological analysis personnel (paragraph 4.C of Section 11.0.4).
c.
The same (or an improved) communications system that was instal-led at the original interim Emergency Operations Facility (E0F) has been installed at the relocated interim E0F.
d.
The same (or an improved) set of operating procedures that were adopted for the original interim Emergency Operations Facility have been adopted for the relocated interim E0F.
e.
Emergency equipment, suitable for its emergency purpose, has been purchased and delivered to the offsite response organiza-tions.
f.
A drill has been conducted to verify the adequacy of the physical design, communications equipment, and operating procedures of the relocated interim E0F.
g.
FEMA has reviewed and confirmed that the E0F, Offsite Dose Assessment Center (0DAC), and Liaison SOPS are adequate.
h.
Consistency has been achieved in the prewritten instructions for the public in the licensees' and the local jurisdictions' emergency plans.
8.
No later than six months after San Onofre Unit 2 commences full power operation:
1.
Both meteorological towers and the Health Physics Computer system shall be fully installed and operational.
SCE shall maintain offsite assessment and monitoring capacities, essentially as described in the hearing, at no less than that level of readiness, until offsite capabilities exist and are acceptable.
l The NRC staff and the licensee shall resolve what further efforts, if 2.
l any, are required to disseminate information to non-English speaking persons in the EPZ regarding actions to be taken in the event of an emergency.
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San Onofre SSER 6 13-2
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3.
The licensee and offsite jurisdictions shall develop and stand ready to implement arrangements for medical services for members of the offsite public who may be contaminated and injured or exposed to high radiation as a result of a serious accident at San Onofre.
4.
The "~ extended" Emergency Planning Zone (EPZ) concept shall be deleted from the San Onofre onsite and offsite plans and the Plume EPZ boundary _shall be extended, along with siren coverage, to Dana Point and all of San Juan Capistrano.
The Board also considered the question of siren adequacy raised by San Clemente Mayor Mecham in his letter of April 26, 1982 to the NRC.
By Order dated June 16, 1982, the Board resolved this question, determining that the siren system is adequate, subject to the confirmation required in Board condition A1, above.
Regarding the Board's condition requiring arrangements for medical services for members of the offsite public, the staff believes that it is not necessary to develop and stand ready to implement arrangements for medical services for members of the offsite public who may be contaminated and injured or exposed to high radiation in a serious accident. The basis for the staff position in this regard is as follows.
The types of radiological impacts that may occur are either (1) superficial contamination not requiring medical treatment, (2) small numbers of con-taminated and non-radiologically injured persons who can be accomodated within the planning for plant personnel, and (3) in worst case accidents, if one postulates large numbers of high radiation exposures, the effects are such that a number of days are available before treatment is needed and that during this time ad hoc plans for transportation to hospital beds anywhere in the U.S.
could be carried out.
Such individuals can easily be identified by nausea symptoms occurring several hours after exposure.
This g hoc approach is consistent with the practice in other areas of emergency preparedness where responses (e.g., plant recovery actions) are not set out in advance in detail but are left to g hoc actions to be taken after the accident.
Notwithstanding the staff's position regarding the need for arrangements for medical services for members of the offsite public, the staff will confirm that each Board condition has either been satisfied prior to issuance of a full power operating license for San Onofre Unit 2, or the license will be conditioned to require that the Board condition be satisfied on the schedule defined by the Board.
Based on our review of the Initial Decision, we conclude that the items the Board required " prior to full power operations" should be completed prior to exceeding 5% power.
Similarly, we conclude that the items the Board required "during the first six months of full power operations" should be completed no later than five months after initially exceeding 5% power. The one month difference will permit the staff to review and confirm that the condition has been satisfied within the six month period.
San Onofre SSER 6 13-3
Subject to confirmation to the Board that the conditions defined under A.1 and A.2, above, have been satisfied, the staff considers all emergency preparedness issues relevant to issuance of a full power license for San Onofre 2 to be resolved.
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14 INITIAL TEST PROGRAM By [[letter::05000361/LER-1982-024-01, /01T-0:on 820606,w/discharge Valve 2HV4713 Inoperable Rendering Flowpath for Motor Driven Auxiliary Feedwater Pump 2P-141 Inoperable,Plant Entered Mode 3. Investigation Re Cause of Oversight Continuing|letter dated June 23, 1982]], SCE requested that it be allowed to delete the (N-1) control element assembly (CEA) test described in Section 14 of the San Onofre 2 and 3 FSAR.
The basis for the request is that the benefits of the test do not, in SCE's opinion, outweigh the financial risk of core damage associated with performing the test.
The staff has evaluated the SCE request and concurs with the SCE argument.
Therefore, the staff will not require that this test be performed at San Onofre 2 and 3.
A discussion of the bases for this position is given below.
Regulatory Guide 1.68 Revision 2, August 1978, on " Initial Test Programs for Water-Cooled Nuclear Power Plants" addresses the issue of control rod (or CEA) reactivity worths in item A.4.b.
This item requires that control rod and rod bank worths be measured to ensure that they are in accordance with design calculations to ensure an adequate shutdown margin consistent with accident analysis assumptions throughout core life.
The Regulatory Guide does not require or prescribe an (N-1) control rod test to satisfy, in part, item A.4.b.
The (N-1) control rod startup physics test consists of a configuration in which the reactor is just critical with all the control rods fully (or nearly fully) inserted except for the highest worth rod which is fully withdrawn from the core.
The reactor is hot, near zero power, and with a low boron concentration (about 100-500 ppm) in the primary coolant water.
In this configuration, the moderator temperature coefficient (MTC) has a large negative value.
If a transient or an accident occurred in this reactor configuration, shutdown reactivity would be available by tripping the high worth withdrawn rod and by injecting boron into the reactor coolant.
The objection to the (N-1) control rod test by SCE is that the test configura-tion has such a large negative MTC that the reactor is vulnerable to, among other things, overcooling transients.
The positive reactivity added by a cooldown may be larger than the negative reactivity added by tripping the withdrawn rod and injection of boron into the reactor coolant.
Substantial fuel failures could occur before enough boron is injected to shut the reactor down.
Since very little burnup has been accumulated by the core, there would be only a small radioactive dose in the event of fuel failures.
The economic impact, however, of such fuel failures could be drastic.
The core physics calculations performed for PWRs have progressed to the point where all of the fuel suppliers have satisfactory methods and procedures.
One can, however, question various aspects of any of the methodologies.
The con-tinuing evaluation of operating experience that the fuel suppliers perform enables them to keep improving their methods and accumulating additional data for use in making model improvements and determining the uncertainty or reduc-ing the uncertainty in various parameters.
Changes in core design can also lead to changes in methodology or require additional benchmarking.
San Onofre SSER #6 14-1
l If one accepts the premise that reactor physics calculations are satisfactory, then startup physics testing has but one basic objective.
This objective is to ensure that the reactor conforms to the design calculations, that is, that the reactor is free of errors in either the design calculations or loading of the reactor.
Only a limited number of physics tests are required to ensure that the reactor conforms to the design calculations.
These tests include power distribution measurements, control rod bank worth measurements, and reactivity coefficient measurements.
Symmetry checks may also be performed using either control rods or the incore/excore nuclear instrumentation system.
This limited number of physics tests at a small number of reactor state points (not neces-sarily operating state points) along with the requirements of the Technical Specifications (and the measurements attendant thereto) are sufficient to conclude that the reactor corresponds to the design calculations for the cycle.
Anomalies result in either Technical Specification violation or off-normal values for measured parameters.
The banefit of performing the (N-1) control rod test is limited to obtaining the worth of the highest worth control rod in a particular reactor state.
It is not explicitly required by Regulatory Guide 1.68.
It is not required to verify design calculations or the shutdown margin for the cycle for present classes of PWRs.
The negative impact of the test is that if has the potential for placing the reactor in an unsafe configuration.
On the basis of these cunsiderations, the staff finds the proposed deletion of the (N-1) control rod test to be acceptable.
1 San Onofre SSER #6 14-2
17 QUALITY ASSURANCE 17.3 Quality Assurance Program The description of the San Onofre 2 and 3 quality assurance program for the operations phase has been updated by Amendment 5 of Section 17.2 of Southern California Edison Company's Topical Report SCE-1-A, " Quality Assurance Pro-3.'am," dated March 1982.
The principal quality assurance program changes in Amendment 5 are (1) an update of the commitments to Regulatory Guides as shown in Table 17-1 and (2) a transfer of the responsibility for directing the activities of quality control personnel onsite from the Plant Manager to the Nuclear QC supervisor who reports to the Manager, Quality Assurance.
The quality control personnel provide site inspection and surveillance of safety-related items and activi-ties.
The staff believes that this revised reporting relationship should enhance the effectiveness of the quality assurance program.
On this basis, we find Amendment 5 to be acceptable.
Table 17-1 Updated regulatory guidance for quality assurance Regulatory Revision No.
Revision Date Guide Prior New Prior New Subject 1.33 1
2 1/77 2/78 QA Program Requirements 1.38 1
2 10/76 5/77 Packing, Shipping, etc.
1.39 1
2 10/76 9/77 Housekeeping 1.58 0
1 8/73 9/80 Inspection Personnel 1.123 0
1 10/76 7/77 Procurement 9/80 Auditing 1.144 1
0 8/80 Audit Personnel 1.146 San Onofre SSER #6 17-1 w
I 22 THI-2 REQUIREMENTS 22.2 Discussion of Requirements I.G.1 Special Low-Power Testing and Training In Supplement No. 1 to the SER the staff requirements and the licensees' commitments regarding special natural circulation testing were discussed.
The staff required that the licensee submit, four weeks prior to conducting the tests, detailed test procedures and a safety analysis.
By letter dated April 15, 1982, SCE provided the required information, thereby satisfying condition 2.B.(19)g of the San Onofre Unit 2 Operating License, NPF-10, issued February 16, 1982.
The proposed natural circulation test was discussed with the licensees in a meeting, in Bethesda, Maryland, on May 20, 1982.
The staff has concluded that the proposed natural circulation tests are acceptable.
The basis for our conclusion is given below.
1.
Description of Tests Per the requirements of Item I.G.1 of NUREG-0737, "Special Low-Power Testing and Training," a special natural circulation test program has been prepared by the San Onofre Unit 2 licensees.
The proposed test program includes the fol-lowing three tests:
(1) Test A1 - Verification of Natural Circulation. The purpose of this test is to establish natural circulation flow conditions.
The test will be performed with the reactor initially critical at approximately 3% power with all four reactor coolant pumps (RCPs) operating.
Certain reactor protective system trips will be bypassed to allow the reactor to be maintained critical with forced reactor coolant circulation secured.
All four RCPs will be simultaneously tripped during the test to establish natural circulation flow in the reactor coolant system.
(2) Test A2 - Verification of Natural Circulation at Reduced Pressures.
The purpose of this test is to demonstrate the capability to maintian natural circulation and adequate margin to saturation without the use of pres-surizer heaters to demonstrate the ability to maintain natural circulation at reduced reactor coolant system (RCS) pressures.
This test will be performed when the reactor power is held constant at 3% power.
The RCS pressure will be maintained at or above 1750 psia during the test to ensure that an adequate subcooled margin exists at all times.
(3) Test A3 - Verification of Natural Circulation with Reduced Heat Removal Capacity.
The purpose of this test is to demonstrate the capability to maintain natural circulation with one steam generator isolated, and to demonstrate that full natural circulation flow can be reestablished when the isolated steam generator is returned to service.
This test will be performed when the reactor power is held at 1% power.
San Onofre SSER #6 22-1
r 2.
Operational and Test Termination Criteria As the result of a safety analysis of the Low Power Test Program at San Onofre Unit 2, the licensees have specified a set of operational criteria for test conditions (See Table 22-1) and a set of test termination criteria (see Table 22-2).
Compliance with the operational and test termination criteria will ensure the following minimum conditions for safe operation are met:
(1) sufficient subcooled margin exists in RCS.
(2) Sufficient water level in each steam generator exists.
(3) Sufficient pressurizer level exists.
(4) Sufficient rod worth is available.
(5) Adequate margin to critical heat flux exists in the core at all times during natural circulation.
(6) The possibility of uncontrolled rod motion is minimized.
(7) The maxi. mum power level is limited in the event of an uncontrolled reactivity addition.
l San Onofre SSER #6 22-2
Table 22-1 Operational Criteria 1.
Operational criteria for Tests A1, A3, and A3:
a.
RCS loop subcooled margin
>20 F b.
Steam generator water level
>60%
c.
Pressurizer water level i
(1) With RCPs running 33 1 2%
(2) Natural circulation
> 33 1 2%
d.
Loop AT 1 58 F e.
T 1 578 F avg f.
Tc 510 F 1 Tc 1 550*F g.
High linear power trip setpoint 9.1%
h.
Core exit temperature (highest T )
1 600 F h
i.
CEA Group 6 (All other full and part
> 60" withdrawn length CEAs to fully withdrawn) j.
Reactor power:
(1) Maximum transient value 1 5%
l (2) Minimum value
> 0.5%
(3) Nominal steady-state value 1% to 3%
(except as otherwise specified) i k.
Sustained reactor startup rate 1 1 DPM 1.
Steam generator pressure
< 1070 psia m.
All CEAs in a group should be within t 1.5 inches of the group average.
n.
Use of the CEDM control system in auto sequential or manual individual mode is prohibited following RCP trip and establishment of natural circulation.
o.
Maintain the CEDM control system in the "off" mode except as required to position Group 6 CEAs only following RCP trip and establishment of natural circulation.
San Onofre SSER #6 22-3
p.
Do not start a RCP when in natural circulation without first manually tripping the reactor q.
Maintain steam generator levels as stead 9 as possible.
r.
If T falls below.510*F, adjust fee dater flow and/or steam flow as necessary to stop the cooldown i
s.
Monitor for RCS void formation 2.
Operational criteria for test A2 (in addition to Item 1 above) a.
Maximum pressurizer cooldown rate
< 200 F in any 1-hour period b.
Do not allow RCS pressure to decrease i
below 1750 psia i
3.
Operational criteria for test A3 (in addition to item 1 above):
a.
Initial steady state power level s1%
prior to steam generator isolation i
b.
Initial steam generator pressure s800 psia 4
prior to steam generator isolation.
i l
i San Onofre SSER #6 22-4
i i
j Table 22-2 Test Termination Criteria (For Tests A1, A2, and A3) 1.
RCS loop subcooled margin
< 20 F i
2.
Any loop AT
> 58*F
>-578*F 3.
T,yg 4.
Core exit temperature (highest Th)
> 600 F 4
5.
Reactor power
> 5%
i 6.
Sustained reactor startup rate
> 1.5 DPM l
7.
Tc
<500*F or >550*F 8.
Any uncontrolled rod motion (Including Rod drop or rod ejection) 9.
RCS pressure can not be adequately controlled 1
San Onofre SSER #6 22-5
i 3
Impact on Plant Technical Specifications Exceptions to a number of technical specification requirements for San Onofre Unit 2 will be made for the duration of the low power test program.
Those technical specification exceptions or modifications are required because the tests involve operation with a critical reactor under conditions outside of the range allowed in the Technical Specifications (e.g., natural circulation con-ditions and low coolant pressure and temperature).
The proposed San Onofre 2 Technical Specifications have been modified following staff review of the low power test program.
Certain exceptions are now delineated as changes with appropriate footnotes to indicate the modified parameter.
It should be noted that exceptions to the listed Technical Specifications only apply to the trip function or setpoint and do not apply to the surveillance require-ments, LCOs, Action Statements, etc.
Certain clarifications to the San Onofre 2 technical specifications are listed below.
These clarifications are provided to explain the reasons for not granting the changes proposed by the licensee.
Specification 2.1.1.1 Safety Limits - Reactor Core - The proposed exception is unnecessary since no safety limits will be exceeded during the proposed low power tests.
These safety limits are not contingent upon reactor coolant flow.
Specification 2.1.1.2 Linear Power Level - high-four reactor coolant pumps operating - New modification resulting from need for reduced setpoint of this parameter.
Specification 3.1.1.4 Minimum Temperature for Criticality - The proposed exception is unnecessary - This is covered by Speci-fication 3.10.6.
The natural circulation tests are i
PHYSICS TESTS as defined in the Technical Specifications and Specification 3.10.6 is applicable.
Specification 3.3.1.3 Logarithmic Power Level - high - The proposed exception l
is unnecessary - trip setpoint modified.
l Specification 3.4.1.1 Reactor Coolant Loops and Coolant Circulation - The proposed exception is unnecessary - Special Test Exception 3.10.3 applies.
Specification 3.4.1.2 Hot Standby - The proposed exception is unnecessary -
LC0 footnote allows 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of no flow condition as long as two provisions maintained.
1 Specification 3.4.3 Pressurizer - The proposed exception is unnecessary -
Pressurizer remains OPERABLE.
l Specification 3.4.4 Steam Generators - The proposed exception is unnecessary - Steam generators remain OPERABLE.
San Onofre SSER #6 22-6
Specification 3.7.1.2 Auxiliary Feedwater System - The proposed exception is unnecessary - Auxiliary feedwater system remains OPERABLE.
For conducting the special low power test program as described in Section 22.2-I.G.1 of Supplement No. 1 to the Safety Evaluation Report, the Technical Specifications may be exempt (E) or modified (C) as follows:
Technical Specifications Test Test Test Section Description Al A2 A3 2.2.1 Reactor Trip Setpoints 2.
Linear Power Level-High C(1)
C(1)
C(1)
Four Reactor Coolant Pumps Operating 3.
Logarithimic Power Level-High C(2)
C(2)
C(2) l l
5.
Pressurizer Pressure-Low C(3) 7.
Steam Gen. Pressure-Low C(4)
C(4)
C(4) 9.
Local Power Density-High E(5)
E(5)
E(5) 10.
DNBR-Low E(5)
E(5)
E(5) 11.
Reactor Coolant Flow-Low E(5)
E(5)
E(5) 3.3.1 Reactor Protective Instrumentation 9.
Local Power Density-High E(5)
E(5)
E(5) 10.
DNBR-Low E(5)
E(5)
E(5) 14.
Core Protection Calculators E(5)
E(5)
E(5) 16.
Reactor Coolant Flow-Low E(5)
E(5)
E(5) 3.3.2 Engineered Safety Feature Actuation System Instrumentation 1.
Safety Injection (SIAS)
C(3) 4.
Main Steam Line Isolation C(4)
C(4)
C(4) 6.
Containment Cooling (CCAS)
C(3) 8.
C(4)
C(4)
C(4)
Notes:
1.
Trip setpoint lowered to 5 9.1% RATED THERMAL POWER, allowable value 1 10.4% RATED THERMAL POWER 2.
Trip setpoint raised to < 100% RATED THERMAL POWER, allowable value i 100% RATED THERMAL POWER 3.
Trip setpoint lowered to 1 1,550 psia 4.
Trip setpoint lowered to 1 550 psia 5.
Trip bypassed San Onofre SSER #6 22-7
4 Safety Evaluation and Conclusions s
4.1 Introduction The licensees submitted the results of a study of the safety effects of'the special conditions of the low power test program, including proposed modifica-tions to the Technical Specifications, which are outside the bounds of conai-tions assumed in the FSAR.
The effects of these conditions on the condition II, III, and IV events treated in Chapter 15 of the San Onofre Unit 2 FSAR were evaluated.
The following criteria were used in this review:
Condition II events, at worst, shall result in a reactor trip with the plant being capable of return to operation.
Condition II events shall not propagate to cause a more serious Condition III or IV event and are not expected to result in fuel rod failure or reactor coolant system overpressurization.
Condition III events are very infrequent faults which will be accommodated with the failure of only a small fraction of the fuel rods, although sufficient fuel damage might occur to preclude immediate resumption of operation.
For infrequent incidents, the plant should be designed to limit the release of radioactive material to assure that doses to persons offsite are limited to values which are a small fraction of 10 CFR Part 100 guideline values.
A Condition III event shall not generate a Condition IV fault or result in loss of function of the reactor coolant system or containment barriers.
Condition IV events are limiting design bases accidents which are not expected to occur, but are postulated because their consequences include a potential i
for the release of significant amounts of radioactive material.
System design l
for Condition IV events will prevent a fission product release to the environ-ment which would result in an undue risk to the health and safety of the public in excess of limits established in 10 CFR Part 100.
A Condition IV event is not to cause a consequential loss of required function of systems needed to mitigate the consequences of the accident, such as the emergency core cooling system and the containment.
The results af the analyses of Condition II, III, and IV events (in RSB review scope) are categorized in Table 22-3 according to the following evaluation bases.
Evaluation Basis Category Bounded by FSAR analysis results 1
Evaluation shows SRP criteria are met 2
Operator action is required for protection 3
Probability of occurrence reduced to acceptable
~
limits by restrictions on operating conditions 4
San Onofre SSER #6 22-8
Table 22-3 Summary of-Safety Evaluation
^'
EVENT Al A2 A3
~
Condition II*
Decrease irt feedwater temperature 2
2 2
,E Increase in'feedwater flow 2
2 2
2 Increase in main steam flow 2
2 2
~
Inadiertent opening of an ADV 1,2 1,2 1,2 Loss of external load 4
4 4
4 4
Loss of condenser vacuum 1,2 1,2 1,2 i
Loss of normal AC power 1,2 1,2 1,2 Partial loss of flow 1
1 1
CEA withdrawal 1,2 1,2 1,2 CEA misoperation 2,3 2,3 2,3 CVCS malfunction (boron dilution).
1 1
1 Startup of inactive RCP 2
2 2
CVCS malfunction (RCS inventory) 1 1
1 Inadvertent operation of ECCS 4
4 4
Condition III Decrease in feedwater temp. with SF 2
2 2
Increase in feedwater flow with SF 2
2 2
Increase in main steam flow with SF 2
2 2
Inadvertent opening of ADV with SF 1,2 1,2 1,2 Loss of external load with SF 4
4 4
Turbine trip with SF 4
4 4
Loss of condenser vacuum with SF 1,2 1,2 1,2 Loss of normal AC Power with SF 1,2 1,2 1,2 i
Loss of feedwater flow 2
2 2
Total loss of RCS flow 1
1 1
Partial loss of RCS flow with SF 1
1 1
CVCS malfunction with SF 1
1 1
Condition IV Steam piping failures 1,2 1,2 1,2 Loss of feedwater flow with SF 2
2 2
Feedwater line break 1,2 1,2 1,2 Reactor coolant pump shaft seizure 1
1 1
Single RCP sheared shaft 1
1 1
Total loss of RCS flow with SF 1
1 1
Improper loading of fuel assembly 1
1 1
CEA ejection 1,2 1,2 1,2 Primary sample or instr. line break 1
1 1
! s 's, SG tube rupture 1
1 1
,d Loss-of-coolant accident 1
1 1
\\
. San Onofrc SSER #6-22-9 q,
x
't
l l
Table 22-4 lists the events for which a qualitative evaluation is sufficient to conclude that the consequences of the event for the low power test program are bounded by the FSAR results.
4.2 Thermal Margin Model In place of the standard TORC /CE-1 methodology (References 1 and 2) the licensees have used the Bowring mixed flow cluster dryout correlation (Reference 3).
This is because the low flow rates for the low power natural circulation tests are well below the data range of the CE-1 critical heat flux (CHF) correlation.
The licer, sees state that a CHFR limit of 1.26 has been obtained based on a 95/95 one sided tolerance limit calculated from test data reported in Reference 3.
The power at which the Bowring correlation yields a minimum CHFR of 1.26 as a function of flow at 2300 psia and 552 F inlet temperature is plotted in Figure 22-1.
It is noted that this figure has a permitted opera-tional line for the given conditions for the low power natural circulation tests which is well below the limit line for CHFR = 1.26.
The natural circula-tion tests are normally to be run at approximately 3% power.
The parameter ranges of applicability for the Bowring correlation from Reference 1 are:
Geometry
90 - 2250 psia Mass Velocity:
0.04 - 3.0 x 106 lbm/ft2 - hr Heated diameter:
0.3 - 1.4 inches Channel length:
60 - 180 inches Radial Peaking Factor:
1.0 - 1.32 (Intra-assembly peak)
Axial Peaking Factor:
1.0 - 1.38 The licensees have used conservative assumptions in applying the Bowring correlation.
These are as follows:
(1) A single closed channel enthalpy rise calculation was used to determine the hot assembly coolant conditions.
The flow rate for the hot assembly was assumed to be equal to the core average flow rate rather than the increased flow expected in the hot assembly for natural circulation.
(2) At high qualities the moderator feedback reduces the power level in the upper region of the core.
However, this effect was not considered.
i l
j (3)
In calculating the CHF at each axial location using the Bowring correla-l tion, the CHFR was determined by dividing the CHF by the local heat flux of the hottest pin in the assembly rather than by the bundle average, j
upon which the Bowring correlation is based.
(
- PTR:
Pressure Tube Reactor; BWR:
Boiling Water Reactor; PWR:
Pressurized Water Reactor.
l l
l l
l San Onofre SSER #6 22-10 I
l
Table 22-4 Events Bounded by FSAR Results Event Reason Why Consequences Bounded by FSAR Partial loss of RCS flow Low power level CVCS malfunction (boron dilution)
Low setpoint of the high linear reactor power trip (at 9.1%) and constant operator monitoring during low power tests.
CVCS malfunction (RCS inventory)
Lower initial pressurizer level allowing more time for the operator to detect the event and constant operator monitoring of pressurizer level during the tests.
Total loss of forced reactor Low power level coolant flow Partial loss of RCS flow with SF Low power level CVCS malfunction with SF Lower initial pressurizer level allowing more time for the operator to detect the event and constant operator monitoring of pressurizer level during the tests.
Reactor coolant pump shaft seizure Prior to coastdown of the RCPs, greater initial thermal margin exists due to lower power level.
Single RCP sheared shaft Prior to coast & wn of the RCPs greater initial thermal margin exists due to lower power level.
Total loss of RCS flow with SF Low power level Primary sample or instrument Lower radioactivity level in RCS than line break the technical specification limit employed in the FSAR analysis.
Steam generator tube rupture Lower radioactivity level in primary and secondary systems than the technical specification limit employed in the FSAR analysis.
Loss-of-coolant accident Lower power level and reduced decay heat l
generated by core.
Improper loading of fuel assembly Low power level San Onofre SSER #6 22-11
Figure 22-1 Fuel Performance and Test Operation Domains in the Reactor Power vs Vessel Flow Space 30 l
25 55 UNACCEPTABLE
- s+d FUEL
@0 PERFORMANCE 2
u.15 a
g +N o
ACCEPTABLE 9
FUEL ce 4
?ERFORMANCE l
o.1 c
+
M 552 F tA, h 8 BET 602 ~ > ", g3g es 5
VIOLATES Tgg1T TEST PROCEDURES TEST DOMAIN e
i e
i i
0-0 500 1000 1500 2000 2500 3000 REACTOR VESSEL FLOW, LBWSEC San Onofre SSER #6 22-12
The licensees have set the following temperature limits for the natural circulation tests:
Thot:
1 600 F hot:
5 T
- 20 F T
sat ATcore: 5 58 4 These temperatures will be used to limit the allowable power as determined by an energy balance.
In natural circulation the flow is dependent on power and the allowable power in the power-to-flow relationship can be determined as a function of pressure, inlet temperature and flow.
We find the thermal margin model using the Bowring correlation acceptable because it is based on data in the suitable range and was used with conserva-tive assumptions for application to San Onofre Unit 2.
In addition the test procedures call for operation at power levels well below the limit line for the Bowring CHF as shown in Figure 22-1.
4.3 Events Reanalyzed to Demonstrate that SRP (NUREG-0800) Criteria are Met l
l 4.3.1 Decrease in Feedwater Temperature l
During the lower power tests, feedwater will be supplied to the steam generators using the auxiliary feedwater system.
This system takes its suction from a condensate storage tank and supplies water which is normally maintained at a temperature of approximately 70 F.
Since preheating of the feedwater does not take place, no significant temperature change is likely given.
The licensees have reevaluated this event and concluded that a large margin to critical heat flux (CHF) would be maintained throughout the event and RCS pressure would remain below design pressure.
Therefore, the consequences of a decrease in feedwater temperature event during the low power tests are found to be acceptable.
4.3.2 Increase in Feedwater Flow During the low power tests, feedwater will be supplied by the auxiliary feed-water system.
The total capacity of this system is approximately 5% of the full power rated feedwater flow, and therefore the potential cooldown due to the maximum possible increase in feedwater flow is less than the maximum cool-down obtained from the increase in main steam flow event discussed in Section 22.2-I.G.1-4.3.3, below.
The licensees have reevaluated this event and have concluded that a large margin to critical heat flux (CHF) would be maintained throughout the event and RCS pressure would remain below design pressure.
Therefore, the consequences of a increase in feedwater flow event during the low power tests are found to be acceptable.
San Onofre SSER #6 22-13
4.3.3 Increase in Main Steam Flow The limiting case of the increase in main steam flow event is identified as a failure in the turbine bypass control system which would result in an opening of one or more of the bypass valves.
The flow rate of each valve is approxi-mately 11% of the full power turbine flow rate.
Tnere are four turbine bypass valves for a total of approximately 45% flow.
During the low power natural circulation tests, it is assumed that due to a spurious signal or operator error, the extent of opening of one or more of the turbine bypass valves is increased.
The resulting increased main steam flow will increase the rate of heat removal by the steam generators, causing cool-down of the RCS.
Due to the negative moderator temperature coefficient, core power will increase.
At the same time, the increased temperature difference between the steam generator inlet and outlet on the primary side, caused by the increase in steam demand, and the increased temperature difference between core inlet and outlet, caused by the incresaed power, will cause an increase in the natural circulation flow.
A variety of natural circulation test results from other Combustion Engineering (CE) plants indicate that at 1% power the natural circulation reactor vessel flow will be greater than 1000 lbm/sec.
Thus the functional relationship, percent power equals the cube of the quantity reactor vessel flow in Ibm /sec divided by 1000, or Q = (W/1000)3, bounds the steady state power that can exist with any steady state natural circulation flow rate.
The results of the licensees' analysis shows that the bounding trajectory for the increase in main steam flow event is bounded by the unacceptable fuel performance curve (CHF = 1.276) and the maximum core power at time of trip for the increase in main steam flow event.
Increase in main steam flow events are, initially, depressurization events.
After reaching a new e<1uilibrium power level, some repressurization may occur.
Even if operator action is not taken and no reactor trip occurs earlier, a reactor trip may occur on high pressurizer pressure at the high pressurizer pressure setpoint.
The auxiliary feedwater system and primary and secondary system safety valves are designed to relieve well in excess of the energy available from the decay heat after operation at full power, while maintaining primary and secondary pressures below the design pressures.
During the low power natural circulation tests, decay heat levels will be more than an order of magnitude lower than the values for which these systems are designed.
Therefore, primary and secondary pressures will remain below design pressures during the increase in main steam flow event that might occur during the low power tests.
Based on the above, we conclude that the consequences of an increase in main steam flow event during the low power tests are acceptable.
4.3.4 Inadvertent Opening of an Atmospheric Dump Valve (ADV)
With respect to fuel performance and RCS pressure, the consequences of any inadvertent opening of a steam generator atmospheric dump valve event that might occur during the low power tests would be no more adverse than those consequences for the increased main steam flow event discussed in Section 22.2-I.G.1-4.3.3, above.
This is because each ADV can only release approxi-mately 5% of the full power steam flow and each turbine bypass valve can San Onofre SSER #6 22-14
1 release approximately 11% of the full power steam flow.
The limiting increase in main steam flow event assumes a failure in the turbine bypass control systems which would result in an opening of one or more of the turbine bypass valves.
Since this event is bounded by the increase in main steam flow event, a large margin to critical heat flux (CHF) would be maintained throughout the event and RCS pressure would remain below design pressures as the results of the incresae in main steam flow event addressed in Section 22.2-I.G.1-4.3.3, above.
The radiological consequences are bounded by the event analyzed in FSAR. This is because the primary and secondary system activities would be substantially lower for the time in life during which the tests will be conducted than the values assumed in the FSAR analyses.
Also, it is due to the low power levels at which the tests will be conducted, wherein less decay heat would have to be removed by possible steam release to the atmosphere during any post event cooldown than the amount of decay heat that was assumed in the FSAR analyses.
Therefore, the consequences of an inadvertent opening of an ADV event during l
the low power tests are found to be acceptable.
4.3.5 Loss of Condenser Vacuum (LOCV)
Upon LOCV the turbine bypass valves close and are blocked from opening.
There l
will be no loss of feedwater following LOCV since feedwater is supplied by the auxiliary feedwater system during the low power tests.
The operator will respond to the increasing hot leg temperature, pressurizer pressure, and secondary pressure by tripping the reactor in addition to terminating the test and restoring forced flow.
The RCS heat removal is accomplished by the operator by manually controlling the steam generator ADVs and the auxiliary feedwater system.
The applicnt has performed quantitative evaluation for this event and find that for the LOCV event during the low power tests, the RCS pressure will remain below 110% of the design pressure and no disruption of natural circula-i tion occurs during the event.
Margin to critical heat flux (CHF) would be maintained throughout the event.
Therefore, the consequences of a LOCV event during the low power tests are found to be acceptable.
4.3.6 Loss of Normal AC Power The loss of normal AC power may result from either a loss of the external grid or a loss of the onsite AC distribution system.
This event is bounded by the LOCV event addressed in Section 22.2-I.G.1-4.3.5, above.
4.3.7 Startup of an Inactive Reactor Coolant Pump (RCP)
During the low power tests, the inadvertent startup of an inactive RCP results in a decrease in core coolant temperature.
The decreasing temperatures may cause power to increase due to a negative moderator temperature coefficient (MTC).
However, the change in power would be small because of the small MTC which exists at the beginning of core life.
The low power tests are performed at the power level less than 5% and a reactor trip would occur if power increase beyond the 12% power level (trip setpoint at 9.1% power considering uncertainties).
With forced circulation provided by one RCP, the heat removal San Onofre SSER #6 22-15
capabilities exceed the natural circulation testing conditions.
The applicant concluded that for the startup of an inactive RCP event during the low power tests, the RCS pressure will remain below 110% of the design pressure and a large margin to critical heat flux (CHF) will be maintained throughoutJhe Therefore, we find the consequences of the startup of an inactive RCP event.
event during the low power tests acceptable.
4.3.8 Loss of Feedwater Flow During the low power natural circulation tests, feedwater is provided by the AFW system under manual control.
Under these conditions, the loss of auxiliary feedwater flow will result in decrease in feedwater flow to both steam generators.
The operator will respond to the decreasing SG level by starting the electric-driven AFW pumps and by terminating the test by tripping the reactor.
The applicant concluded that the decrease in feedwater event results in negligible effect on the RCS response and, hence, has a negligible effect on the RCS pressure and fuel performance.
We find the consequences of this event acceptable.
4.3.9 Increased Heat Removal Events with a Single Failure The applicant has evaluated the event combinations of incresaed heat removal events (e.g., decrease in feedwater temperature, increase in feedwater flow, increase in main steam flow, and inadvertent opening of ADV) with single failure of an active component for the low power tests.
Since none of the single failures considered in the FSAR alter the cooldown rate, the transient behavior of the RCS will not be altered by combining a single failure with the increased heat removal event.
Therefore, the consequences of the events in combination with a single failure are no more adverse than the event conse-quences addressed in Section 22-I.G.1-A.3.1 through Section 22.2-I.G.1-4.3.4, above.
4.3.10 Decreased Heat Removal Events with a Single Failure The applicant has evaluated the event combinations of decreased heat removal events (e.g., loss of condenser vacuum, loss of normal ac power and loss of feedwater flow) with single failure of an active component for the low power tests.
Since none of the single failures considered could cause more severe transients than the events without a single failure, the consequences of these events in combination are bounded by the consequences of the event without a single failure addressed in Section 22.2-I.G.1-4.3.5, Section 22.2-I.G.1-4.3.6 and Section 22.2-I.G.1-4.3.8, above.
4.3.11 Steam System Piping Failures Steam line breaks (SLB) are initially depressurization events.
During the portion of the transient after steam generator dryout and before operator action, some repressurization can occur due to safety injection pump flow, decay heat addition, and heat transfer from the hotter walls and structure of the RCS.
However, the auxiliary feedwater system and the primary and secondary system safety valves are designed to maintain primary and secondary pressure below the system design pressures.
Further, during the low pwer tests, decay San Onofre SSER #6 22-16
heat levels will be more than an order of magnitude lower than the design value.
If an SLB occurs after reactor trip, the consequences would be no worse than those presented in the FSAR since the reactor would be subcritical at the time of event initiation.
The decay heat addition from the San Onofre 2 core after reactor shutdown would be somewhat less than the decay heat addition that was assumed in the FSAR calculation for a SLB at hot zero power.
Therefore the resulting cooldown would slightly be greater for a SLB during the low power tests.
However, the overall effects of less decay heat are judged to be so small that the overall FSAR SLB analysis bounds the low power test conditions.
The potential for degradation in fuel performance during the pre-trip portion of the transient is, in general, maximum for a SLB of less than the maximum possible break area.
Very large breaks result in early reactor trip on low steam generator pressure.
The licensees stated that it has been found that the break area which maximizes the potential for pre-trip degradation in fuel performance for the low power tests is less than the effective area of the turbine bypass valves. Therefore, the results of the SLB event which maximizes pre-trip degradation in fuel performance are identical to the results of the increased main steam flow event addressed in Section 22.2-I.G.1-4.3.3, above.
The licensees have concluded that for SLB accident during the low power tests, the RCS pressure will remain below 110% of the design pressure.
A large margin to CHF would be maintained through-out the event.
There would be no post-trip return to criticality.
Therefore, the consequences of a SLB accident during the low power tests and found to be acceptable.
4.3.12 Feedwater Line Break A feedwater line break (FWLB) may occur due to a pipe failure in the main or auxiliary feedwater system.
The feedwater line breaks resulting in an RCS cooldown are bounded by the steam line break analysis addressed in Section 22.2-I.G.1-4.3.11, above.
For breaks which result in a heatup of the RCS and the blowdown of one steam generator, the FWLB event analyzed in the FSAR is more severe than a FWLB occurring during the low power natural circulation l
tests.
This is because under natural circulation conditions, only the lower portion of the U-tube region is effectively transferring heat from the primary to secondary fluid.
Thus, for the low power tests, the steam generator inventory drops below the low SG 1evel reactor trip setpoint before any significant decrease in heat removal capability occurs.
Therefore, the mismatch in power generation and heat removal at the secondary side is much more severe for the FSAR analysis than for a FWLB during the low power tests.
The applicant has reanalyzed the FWLB accident and concluded that for FWLB accident during the low power tests, the RCS pressure will remain below 110% of the design pressure and no disruption of natural circulation occurs during the event.
Margin to critical heat flux (CHF) would be maintained throughout the event.
Therefore, the consequences of a FWLB accident during the low power tests are found to be acceptable.
4.3.13 Uncontrolled Control Element Assembly (CEA) Withdrawal The uncontrolled CEA withdrawal transient was analyzed from low power levels ranging from 10 4 to 5.5%.
For natural circulation conditions, a CEA with-drawal results in an increase in flow as the power increases.
Due to the high San Onofre SSER #6 22-17
power trip, the maximum power reached is approximately 12% and the flow at this power level is calculated to be sufficient to provide adequate thermal margin to CHF.
During the power ascension tests, the CPCs will be operating to prevent violation of the specified acceptable fuel design limits (SAFDL).
Under these conditions, the event is bounded by the FSAR analysis.
Therefore, the consequences of a CEA withdrawal event during the natural circulation tests are found to be acceptable.
4.3.14 CEA Misoperation During the low power tests, the part length rods will not be inserted.
There-fore, only the full length rod drop events, which result in an initial decrease in core power, were considered.
The power will remain below its pre-drop value until additional moderator feedback due to the cycling of colder coolant through the core occurs.
Since it will take the coolant at least four minutes to completc the cycle, adequate time is available for the operator to sense a dropped rod and terminate testing by tripping the reactor, as required by the test procedures, before any iacrease in local power occurs.
During the power ascension tests, the CPCs will be operating to prevent violation of the SAFDL.
Under these conditions, the event is bounded by the FSAR analysis.
Therefore, the consequences of a CEA misoperation event during the natural. circulation tests are found to be acceptable.
4.3.15 Inadvertent Loading of a Fuel Assembly in an Improper Position Since the power level during these tests is lower than that assumed in the FSAR analyses, the impact of any increase in radial power peaking due to a fuel assembly misloading would be less severe than that indicated in the FSAR.
Constant monitoring of neutron power during the tests also provides assurance that the consequences of the event will be mitigated.
Therefore, a fuel misloading event is found to be bounded by the consequences presented in the FSAR and, hence, acceptable.
4.3.16 CEA Ejection Limitation of operation of the reactor with CEA insertion restricted by the Technical Specifications makes an ejected rod worth less than the delayed neutron fraction.
This results in a CEA ejection transient which is relatively mild compared to those analyzed in the FSAR.
The rate of power increase would be slow enough to preclude any substantial overshoot between receipt of a trip signal and shutdown.
This increase will be terminated by either a manual trip or a high linear power trip at or below 12% rated power.
Peak RCS pressure during the transient is lower than that presented in the FSAR.
A conservative estimate of 9% of the fuel pins are assumed to experience CHF and, thus, cladding failure.
The low fission product inventory due to the low burnup at the time of the low power tests would allow substantially higher cladding failures without violating the 10 CFR 100 dose limits.
We, therefore, find the consequences of a CEA ejection event during the natural circulation tests to be acceptable.
San Onofre SSER #6 22-18 l
4.4 Conclusions The Low Power Test Program for San Onofre Unit 2 involves three tests (A1, A2 and A3) at low power levels conducted over a short period of time and with a very low fission product inventory.
On the bases of the above considerations, the proposed operational and test termination criteria and the safety evaluation which includes the effects of the exceptions to the Technical Specifications and operation under natural circulation conditions, the staff concludes that the Low Power Test Program will not result in undue risk to public health and safety and is acceptable.
l I
l San Onofre SSER #6 22-19
APPENDIX A CONTINUATION OF CHRONOLOGY OF RADIOLOGICAL REVIEW February 2,1982 Letter from applicants transmitting updated status of outstanding items relative to Environmental Qualifica-tion Report.
February 4, 1982 Letter from applicants transmitting Revision 4 to Offsite Dose Calculation Manual.
February 8, 1982 Generic Letter 82 Nuclear Power Plant Staff Working Hours.
Febtuary 8, 1982 Letter from applicants advising of correct classifica-tion of two Potential Finding Reports.
February 9, 1982 Letter from applicants forwarding information on Technical Specification relief requested for radiation monitors.
February 9, 1982 Letter from applicants advising that Unit 2 is ready'for fuel loading and low power testing.
February 9, 1982 Letter from applicants advising that documentation on NUREG-0737 Items I.C.1, II.K.2.17, and II.K.3.30 will be submitted by May 1, 1982.
I February 9, 1982 Letter from applicants transmitting Pump Relief Request No. 4.
February 11, 1982 Letter from applicants requesting " full operational capability" date be revised to January 1, 1983.
February 11, 1982 Letter from applicants transmitting Revision 5 to Offsite Dose Calculation Manual.
February 11, 1982 Letter from applicants transmitting information on effluent monitoring capability for the turbine driven auxiliary feedwater pump exhaust.
February 11, 1982 Letter from applicants updating General Atomics Interim Report forwarded January 25, 1982.
February 16, 1982 Issuance of Amendment 3 to Construction Permits CPPR-97/98 to authorize increase in ownership share of City of Anaheim by 1.5%.
San Onofre SSER #6 A-1
February 16, 1982 Issuance of Supplement No. 5 to Safety Evaluation Report.
February 16, 1982 Issuance of Facility Operating License NPF-10 for Unit 2 authorizing fuel loading and operation at 5% power.
February 19, 1982 Letter from licensees transmitting Revision 6 to Offsite Dose Calculation Manual.
February 19, 1982 Letter from licensees transmitting more legible copies of certain pages of Potential Finding Reports.
February 23, 1982 Letter to licensees requesting commitment to partici-pate in Combustion Engineering effort on feed and bleed capability.
March 3, 1982 Letter from licensees forwarding " Inservice Inspection and Testing Program Plan."
March 3, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 4, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 4, 1982 Letter to licensees requesting that Potential Finding Reports be transmitted on a weekly basis, and related discussion and disposition be included in final report.
March 8, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 9, 1982 Generic Letter 82 Use of INP0 SEE-IN Program.
March 10, 1982 Letter from licensees transmitting an additional Potential Finding Report.
March 10, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 10, 1982 Letter from licensees forwarding responses to questions on heated junction thermocouple reactor vessel level measurement system.
March 12, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 15, 1982 Letter from licensees forwarding data required by Technical Specification Section 6.9.1.10.
March 15, 1982 Letter from licensees transmitting Revision 7 to Offsite Dose Calculation Manual.
San Onofre SSER #6 A-2
l March 16, 1982 Meeting with licensees to discuss the design verifica-tion program.
March 16, 1982 Letter to Combustion Engineering advising that reports submitted by licensee on January 22 will be withheld I
from disclosure.
l March 16-18, 1982 Meeting with licensees to discuss inservice testing program.
March 17, 1982 Generic Letter 82 Post-TMI Requirements.
March 18, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 19, 1932 Letter from licensees transmitting several additional Potential Finding Reports.
March 19, 1982 Letter from licensees transmitting several additional i
Potential Finding Reports.
March 22, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 22, 1982 Letter from licensees providing information regarding resolution of FEMA findings on emergency planning.
l March 22, 1982 Letter from licensees forwarding outline of final report I
on verification program.
March 22, 1982 Letter from licensees requesting change to Technical Specifications to clarify code requirements for shutdown cooling system relief valve.
March 25, 1982 Letter from licensees transmitting several additional Potential Finding Reports.
March 25, 1982 Letter from licensees forwarding response to question on heated junction thermocouple reactor vessel level measurement system.
March 27, 1982 Letter to licensees concerning rapid depressurization and decay heat removal.
March 30, 1982 Issuance of Amendment No. 1 to NPF-10 in response to request of March 22, 1982.
March 31, 1982 Letter from licensees advising that health physics computer system will be implemented by January 1, 1983.
April 1, 1982 Letter from licensees forwarding changes to security plan.
San Onofre SSER #6 A-3
April 1, 1982 Letter from licensees forwarding drawings and associated information for seismic trip system.
April 1, 1982 Letter from licensees forwarding preliminary evaluation of EPRI program test results regarding capability of relief and safety valves to operate under expected operating and accident conditions.
April 5, 1982 Letter from licensees transmitting " Independent Verifi-cation of San Onofre Nuclear Generating Station Units 2 and 3 Seismic Design and Quality Assurance Program Effectiveness."
April 7, 1982 Letter from licensees transmitting proposed change to Technical Specification to eliminate trip setpoint and response time data.
April 9, 1982 Letter from licensees concerning schedule for providing information on existing capability for rapid depressuri-zation and decay heat removal without power operated relief valves.
April 9, 1982 Board Notification 82 ACRS Letter on Reliability of the Shutdown Heat Removal System on the System 80 Design.
April 12, 1982 Meeting with licensees to discuss final report', GA Design Verification Program.
April 15, 1982 Generic Letter 82 Transmittal of NUREG-0909 Relative to the Ginna Tube Rupture.
April 15, 1982 Letter from licensees forwarding " Natural Circulation Test Program Safety Evaluation" and other related reports on procedures and program.
April 15, 1982 Letter from licensees transmitting current status and/or schedule for NUREG-0737 items identified in Generic Letter 82-05.
April 16, 1982 Letter from licensees transmitting formal request for Technical Specification change, replacing April 7 submittal.
April 20, 1982 Generic Letter 82 Environmental Qualification of Safety-Related Electric Equipment.
I i
April 20, 1982 Meeting with licensees to discuss containment purge vent stack monitors.
I April 22, 1982 Letter from licensees forwarding revised emergency planning procedures.
l San Onofre SSER #6 A-4
i April 22, 1982 Letter from licensees advising that the safety valve position indication system has been environmentally and seismically qualified.
April 27, 1982 Letter from licensees transmitting " Procedural (fuidelines for Reactor Coolant Gas Vent System" and Operating Instruction 5023-3-2.33 to satisfy requirements of TMI Action Plan Item II.B.1.
April 27, 1982 Letter from licensees forwarding information on cost of inadequate core cooling instrumentation.
April 28,1982 Letter from licensees transmitting " Effects of Vessel Head Voiding During Transients and Accidents in C-E NSSS Prepared for C-E Owners Group."
April 28, 1982 Letter from licensees advising that Combustion Engineering Report CEN-203, Revision 1 satisfies license condition on small break loss-of-coolant accidents.
April 30, 1982 Letter from licensees forwarding " Final Report, Evalua-4 tion of Heavy Load Handling Operations" and other additional information regarding cranes.
April 30, 1982 Letter from licensees concerning submittal of information on emergency procedure guidelines.
April 30, 1982 Letter from licensees transmitting report on review of rapid depressurization and decay heat removal capabilities.
April 30, 1982 Issuance of Amendment No. 2 to Facility Operating License NPF-10 in response to request of April 7.
May 7, 1982 Board Notification 82 (Transmittal of) Information Items Regarding Emergency Planning.
May 7, 1982 Meeting with licensees to discuss containment tendon surveillance.
May 13, 1982 Letter from licensees forwarding report regarding compliance with Regulatory Guide 1.97.
May 14, 1982 Letter from licensees transmitting several proposed changes to Technical Specifications.
May 14, 1982 Letter from licensees forwarding Annual Reports for 1981.
May 14, 1982 Board Notification 82 (Transmittal of) Information Regarding Emergency Preparedness - Public Warning System at San Onofre.
San Onofre SSER #6 A-5
l May 19, 1982 Letter from licensees forwarding proposed changes to Technical Specifications concerning auxiliary feedwater pump load sequence and number of cold leg high pressure safety injection flow channels.
May 20, 1982 Submittal of Amendment No. 29 to FSAR and Amendment No. 11 to the " Fire Hazards Analysis (FHA) and Comparison with Appendix A of NRC Branch Technical Position 9.5-1, October 1977."
May 20, 1982 Meeting with licensees to discuss natural circulation testing.
May 20, 1982 Letter from licensees proposed change to Technical Specifications to clarify requirement for response time testing for Auxiliary Feedwater Train.
May 21, 1982 Letter from licensees requesting revision to Technical Specifications to make them consistent with current valve response time requirements.
May 21, 1982 Letter to licensees confirming telephone authorization of May 20 changes to Technical Secifications in response to requests of May 19 and 20, 1982.
May 22, 1982 Letter from licensees providing clarifying information relative to May 21 letter requesting Technical Specifica-tion changes.
May 24, 1982 Meeting with licensees to discuss auxiliary feedwater pump environmental qualification.
May 26, 1982 Letter to licensees requesting additional information on Process Control Program.
May 26, 1982 Letter to licensees confirming telephone authorization of May 22 changes to Technical Specifications on contain-ment emergency cooling.
[
June 3, 1982 Letter from licensees transmitting responses to questions l
regarding Process Control Program.
I l
June 4, 1982 Letter from licensees advising that problems with sirens have been corrected and siren operability has been confirmed.
June 4, 1982 Letter from licensees in response to Generic letter 82-10, forwarding current status and/or schedule of NURGE-0737 items identified in that letter.
l San Onofre SSER #6 A-6
APPENDIX B PRINCIPAL NRC STAFF REVIEWERS H. Rood Project Manager J. Eckhardt Design Verification Program J. Knight Design Verification Program W. Haass Design Verification Program C. Liang Shutdown Cooling System and Natural Circulation Testing J. Sears Emergency Preparedness D. Matthews Emergency Preparedness J. Spraul Quality Assurance B. Elliot Reactor Vessel Integrity C. Anderson Unresolved Safety Issues H. Balujian Natural Circulation Testing L. Kopp Natural Circulation Testing D. Fieno Startup Testing San Onofre SSER #6 B-1
APPENDIX C NUCLEAR REGULATORY COMMISSION UNRESOLVED SAFETY ISSUES In the San Onofre 2 and 3 Safety Evaluation Report (SER), we described the status of the Nuclear Regulatory Commission's Unresolved Safety Issues (USIs) that were applicable to the facility.
Since the SER was issued (February 1981), new USIs have been defined.
The new USIs defined since the SER was issued are listed below.
(1) Shutdown Decay Heat Removal - Task A-45 (2) Seismic Qualification of Equipment in Operating Plants - Task A-46 (3) Safety Implications of Control Systems - Task A-47 (4) Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equip-ment - Task A-48 (5) Pressurized Thermal Shock - Task A-49 The staff has reviewed the five USIs listed above as they relate to San Onofre 2 and 3.
Discussion of each of these issues, including references to the related sections of the SER and its supplements, are provided below.
Based on our review of these items as discussed below, we have concluded that San Onofre 2 and 3 can be operated prior to the ultimate resolution of these issues without endangering the health and safety of the public.
A-45 Shutdown Decay Heat Removal Requirements Under normal operating conditions, power generated within a reactor is removed as steam to produce electricity through a turbine generator.
Following a reactor shutdown, a reactor produces insufficient power to operate the turbine; however, the radioactive decay of fission products continues to produce heat (so-called decay heat).
Therefore, when reactor shutdown occurs, other measures must be available to remove decay heat from the reactor to ensure that high temperatures and pressures do not develop that could jeopardize the reactor and the reactor coolant system.
It is evident, therefore, that all light-water reactors (LWRs) share two common decay-heat-removal functional requiremen+s:
(1) to provide a means of transferring decay heat from the reactor coolant system to an ultimate heat sink and (2) to maintain sufficient water inventory inside the reactor vessel to ensure adequate cooling of the reactor fuel.
The reliability of a particular power plant to perform these functions depends on the frequency of initiating events that require or jeopardize decay heat removal operations and the probability that required systems w'ill respond to iemove the decay heat.
San Onofre SSER #6 C-1
The TMI-2 accident demonstrated how a relatively common fault, which the operator should have been able to cope with easily, could escalate into a potentially hazardous situation, accompanied by severe financial losses to the utility, because of difficulties arising in the decay heat removal (DHR) process.
Other circumstances of a more unusual nature (for example, damage to systems by external events such as floods or earthquakes, or by sabotage) which could make j
removal of the decay heat difficult, can also be foreseen.
The question arises, therefore, whether current licensing design requirements are adequate to ensure that LWRs do not pose unacceptable risk as a result of failure to remove shutdown decay heat, and whether, at a cost commensurate with the increase in safety that could be achieved, improvements could be made in the effectiveness of shutdown decay heat removal in one or more transient or i
accident situations.
Resolution of this question is considered to be of sufficient importance to merit raising it to the status of a USI.
To some extent, the effectiveness of the DHR systems is linked to that of the onsite and offsite electrical supplies; the performance and reliability of those supplies is being considered in USI A-44, " Station Blackout." Conse-quently, the scope of work required in relation to the DHR systems is com-plementary to Task A-44, which was discussed in the San Onofre 2 and 3 SER.
The overall purpose of Task A-45 is to evaluate the adequacy of current licensing design requirements to ensure that nuclear power plants do not pose an un-acceptable risk because of failure to remove shutdown decay heat.
This will require the development of a comprehensive and consistent set of shutdown cooling requirements for existing and future LWRs, including the study of alternative means of shutdown decay heat removal and of diverse " dedicated" systems for this purpose.
l This USI will evaluate the benefit of providing alternate means of decay heat j
removal that could substantially increase the plant's capability to handle a broader spectrum of transients and accidents.
The study will include a number of plant-specific evaluations of DHR systems and will result in recommendations regarding the desirability of, and possible design requirements for, improve-ments in existing systems or an alternative DHR method, if the improvements or alternatives can significantly reduce the overall risk t, the public in a cost-effective manner.
An integrated systems approach to the problem will be employed Accordingly, quantitative methods will be used, where possible, to define design require-ments for future plants and to measure.the effectiveness and acceptability of the shutdown DHR systems in existing plants.
The principal means for removing the decay heat in a PWR under normal con-ditions immediately following reactor shutdown is through the steam generators, by the use of the auxiliary feedwater system.
In addition to the WASH-1400 study, later reliability studies and related experience from the Three Mile Island Unit 2 (TMI-2) accidert have reaffirmed that the loss of capability to remove heat through the steam generator is a significant contributor to the i
San Onofre SSER #6 C-2
probability of a core-melt event.
The staff's review of the auxiliary feed-water system design and operation is described in Section 10.4.6 of the SER and Supplement No. 4 to the SER, and in Section 22 (Items II.E.1.1 and II.E.1.2) of Supplement No. 1 to the SER.
It should be noted as discussed below that many improvements to the steam generator auxiliary feedwater system were required of the licensees by the NRC following the TMI-2 accident.
However, the staff still believes that providing an alternative means of decay heat removal could substantially increase the plant's capability to deal with a broader spectrum of transients and accidents and potentially could, therefore, significantly reduce the overall risk to the public.
Consequently, this unresolved safety issue will investigate alternative means of decay heat removal in PWR plants, including but not limited to, the use of existing equipment where possible.
This study will include a representa-tive sample of plant-specific evaluations of DHR systems.
It will result in recommendations regarding the adequacy of existing DHR requirements and the desirability of, and possible design requirements for, an alternative DHR method, other than that normally associated with the steam generator and i
secondary coolant system.
The auxiliary feedwater (AFW) system is a very important safety system in a PWR in terms of providing a heat sink via the steam generators to remove core decay l
heat.
As mentioned above, the TMI-2 accident and subsequent studies have I
further highlighted the importance of the AFW systems.
As discussed below, the staff has re.1uired certain upgrading of the auxiliary feedwater systems for all LWRs following the TMI-2 accident.
Although alternative means of decay heat removal will be investigated under this USI, the staff concludes that, in general, if the licensees comply with the upgrading of requirements for the AFWS, the action taken following the TMI-2 accident justifies continued opera-tion and licensing pending completion of this USI.
Further discussion and the basis for this view are provided below.
TMI-2 Accident The accident at TMI-2 on March 28, 1979, involved a main feedwater transient coupled with a stuck-open pressurizer power-operated relief valve and a temporary failure of the auxiliary feedwater system, and subsequent operator intervention to severely reduce flow from the safety injection system.
The resulting severity of the ensuing events and the potential generic aspects of the acci-dent on other operating reactors led the NRC to initiate prompt action to:
(1) ensure that other reactor licensees, particularly those with plants similar in design to that of TMI-2, took the necessary action to substantially reduce the likelihood for THI-2-type events, and (2) investigate the potential generic implications of this action on other operating reactors.
The Bulletins & Orders Task Force (B&OTF) was established within the NRC Office of Nuclear Reactor Regulation (NRR) in early May 1979 and completed its work on December 31, 1979.
This task force was responsible for reviewing and directing the THI-2-related staff activities associated with the NRC Of fice of Inspection and Enforcement (IE) Bulletins, Commission Orders, and generic evaluations of loss-of-feedwater transients and small-break loss-of-coolant accidents for all operating plants to ensure their continued safe operation.
NUREG-0645, " Report San Onofre SSER #6 C-3
of the Bulletins and Orders Task Force," summarizes the results of the work performed.
Generic and Plant-Specific Studies For B&W-designed operating reactors, un initial NRC staff study was completed and published in NUREG-0560, " Staff Report on the Generic Assessment of Feed-water Transients in Pressurized Water Reactors Designed by the Babcock & Wilcox Company." This study considered the particular design features and operational history of B&W-designed operating plants in light of the TMI-2 accident and related current licensing requirements. As a result of this study, a number of findings and recommendations resulted that are now being pursued.
Generally, the activities involving the B&W-designed reactors are reflected in the actions specified in the Commission Orders.
Consequently, a number of actions have beer, specified regarding transient and small-break analyses, up-grading of auxiliary feedwater reliability and performance, procedures for operator action, and operator training.
The results of the NRC staff review of the B&W small-break analysis is published in NUREG-0565, " Generic Evaluation of Small-Break Loss-of-Coolant Accident Behavior in Babcock & Wilcox-Designed Operating Plants."
Similar studies have been completed for operating plants designed by Westinghouse
(}!), Combustion Engineering (CE), and General Electric (GE).
Those studies, which also focus specifically on the predicted plant performance under different accident scenarios involving feedwater transients and small-break loss-of-coolant accidents, are published in NUREG-0611, " Generic Evaluation of Feedwater Transients and Small-Break Loss-of-Coolant Accidents in Westinghouse-Designed Operating Plants;" NUREG-0635, " General Evaluation of Feedwater Transient and Small-Break Loss-of-Coolant Accidents in Combustion Engineering-Designed Operating Plants;" and NUREG-0626, " Generic Evaluation of Feedwater Transients and Small-Break Loss-of-Coolant Accidents in GE-Designed Operating Plants and Near-Term Operating License Applications."
Based on the review of the operating plants in light of the TMI-2 accident, the NRC staff reached the following conclusions:
(1) The continued operation of the operating plants is acceptable provided that certain actions related to the plants' design and operation and training of operators identified in NUREG-0645 are implemented consistent with the recommended implementation schedules.
(2) The actions taken by the licensees with operating plants in response to the IE Bulletins (including the actions specified in NUREG-0623, "Gei.eric Assessment of Delayed Reactor Coolant Pump Trip During Small Break Loss-of-Coolant Accidents in Pressurized Water Reactors") provide added assurance for the protection of the health and safety of the public.
In addition, the B&OTF independently confirmed the safety significance of those related actions recommended by other NRR task forces as discussed in NUREG-0645.
l San Onofre SSER #6 C-4 1
Pressurized-Water Reactors (PWRs)
The primary method for removal of decay heat from pressurized water reactors is via the steam generators to the secondary system.
This energy is transferred on the secondary side to either the main feedwater or auxiliary feedwater systems, and is rejected to either the turbine condenser or the atmosphere via the secondary coolant system safety / relief valves.
Following the TMI-2 accident, the importance of the AFW was highlighted and a number of improvements were made to improve the reliability of the AFW (see NUREG-0645).
It was also required that operating plants be capable of providing the required AFW flow for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> from one AFW pump train independent of any ac power source; that is, if both offsite and onsite ac power sources were lost.
Some pressurized water reactors potentially have at least one alternate means of removing decay heat if an extended loss of feedwater is postulated.
This method is known as " feed and bleed" and uses the high pressure injection (HPI) system to add water coolant (feed) at high pressure to the primary system (see Section 15.7.2).
The decay heat increases the system pressure, and energy is removed through the power-operated relief valves (PORVs) and/or the safety valves (bleed), if necessary.
It should be noted that some PWRs incorporate HPI pumps that cannot operate at full system pressure (cutoff head about 1500 psi).
For those cases, the PORVs can be manually opened, thereby reducing the system pressure to within the operating range of the HPI.
Limited vendor analyses have shown that the core can be adequately cooled by this means provided that the containment pressure can be controlled to a safe level.
When the primary system is at low pressure, the long-term decay heat is removed by the residual heat removal system to achieve and maintain cold shutdown conditions.
USI A-45 will also consider the adequacy of reliability and performance criteria and standards for RHR systems.
The staff's review of the residual heat removal system design and operation is described in Section 5.4.3 of the SER, Supplement No. 5 to the SER, and this supplement to the SER.
Conclusion In summary, because of the upgrading of current DHR systems that was required following the TMI-2 accident, it is concluded that, in general, plants may continue to be licensed and operated before the ultimate resolution of this generic issue without endangering the health and safety of the public.
- However, licensee compliance with the upgrading of DHR system requirements must be examined by the staff on an individual basis.
For San Onofre 2 and 3, the staff position on this issue is given in Section 5.4.3 of the SER, Supplement No. 5 to the SER, and this supplement to the SER.
Based on the information given above, and on the information presented in Section 5.4.3 of the SER and its supplements, we conclude that San Onofre 2 and 3 can be operated prior to the ultimate resolution of this generic issue without endangering the health and safety of the public.
A-46, Seismic Qualifications of Equipment in Operating Plants The design criteria and methods for the seismic qualifications of mechanical and electrical equipment in nuclear power plants have undergone a significant change during the course of the commercial nuclear power program.
San Onofre SSER #6 C-5
Consequently, the margins of safety provided in existing equipment to resist seismically induced loads and perform the intended safety functions may vary considerably among plants licensed in different time frames.
The staff has determined that the seismic qualification of the equipment in operating plants should be reassessed to ensure the ability to bring the plant to a safe shut-down condition khen subject to a seismic event.
The objective of this un-resolved safety issue is to establish an explicit set of guidelines that could be used to judge the adequacy of the seismic qualification of mechanical and electrical equipment at all operating plants in lieu of attempting to backfit current design criteria.
This guidance will concern equipment required to safely shut down the plant as well as equipment whose function is not required for safe shutdown, but whose failure could result in adverse conditions that might impair shutdown functions.
Our evaluation of San Onofre 2 and 3 seismic qualification is given in Sec-tion 3.10 of Supplement No. 2 to the SER issued on May 8, 1981. As stated therein, we concluded that an appropriate qualification program has been defined and implemented for the seismic Category I mechanical and electrical equipment which will provide reasonable assurance that such equipment will function properly during and after the excitation from vibratory forces imposed by the safe shutdown earthquake.
Such a program constitutes an acceptable basis for satisfying the applicable requirements of General Design Criterion 2.
When the USI A-46 guidelines are developed, San Onofre 2 and 3 will be compared against them, and any modifications deemed necessary at that time will be required to be made.
In the interim, the conclusions given in SER Sup-plement No. 2 provide an acceptable basis for plant operation.
A-47 Safety Implications of Control Systems This issue concerns the potential for transients or accidents being made more severe as a result of control system failures or malfunctions.
These failures or malfunctions may occur independently or as a result of the accident or transient under consideration.
One concern is the potential for a single failure such as a loss of a power supply, short circuit, open circuit, or sensor failure to cause simultaneous malfunction of several control features.
Such an occurrence could conceivably result in a transient more severe than those transients analyzed as anticipated operational occurrences.
A second concern is for a postulated accident to cause control system failures that could make the accident more severe than analyzed.
Accidents could conceivably cause control system failures by creating a harsh environment in the area of the control equipment or by physically damaging the control equipment.
It is generally believed by the staff that such control system failures would not lead to serious events or result in conditions that safety systems could not handle safely.
Detailed systematic evaluations of all nonsafety systems, however, have not been performed to verify this belief.
The potential for an accident that could affect a particular control system, and effects of the control system failures, may differ from plant to plant.
Therefore, it is not possible to develop generic answers to these concerns, but rather plant-specific evaluations are required.
The purpose of this unresolved safety issue is to define generic criteria that will be used for plant-specific evaluations.
San Onofre SSER #6 C-6
The San Onofre 2 and 3 control and safety systems have been designed with the j
goal of ensuring that control system failures will not prevent automatic or manual initiation and operation of any safety system equipment required for accident mitigation and/or to maintain the plant in a safe shutdown condition following any anticipated operational occurrence or " accident." This has been I
accomplished by p.-oviding independence and physical separation between safety system trains and between safety and nonsafety systems.
For the latter, as a minimum, isolation devices were provided.
These devices preclude the propaga-tion of nonsafety system equipment faults to the protection systems.
Also, to ensure that the operation of safety system equipment is not impaired, the single-failure criterion has been applied in the plant design.
A systematic evaluation of the control system design, as contemplated for this unresolved safety issue, has not been performed to determine whether postulated accidents could cause significant control system failures which would make the accident consequences more severe than currently analyzed.
However, a wide l
range of bounding transients and accidents is currently being analyzed to
~
ensure that the postulated events such as steam generator overfill and over-I cooling events would be adequately mitigated by the safety systems.
In addition, systematic reviews of safety systems are being performed with the goal of ensuring that control system failures (single or multiple) will not defeat safety system action.
(
I Also, the licensee has been required by NRC Information Notice 79-22, ("Qualifi-l cation of Control Systems," September 17, 1979) to review the possibility of consequential control system failures which exacerbate the effects of high-energy line breaks (HELB) and adopt new operator procedures, where needed, to ensure that the postulated events would be adequately mitigated.
As part of the review, the staff evaluated the qualification program to ensure that equipment that may potentially be exposed to HELB environments has been adequately qualified or an adequate basis has been provided for not qualifying the equip-ment to the limiting hostile environment.
The staff's evaluation of the licensee's response to Information Notice 79-22 and the adequacy of the qualifi-cation program is reported in Sections 7.7.1 of Supplement No. 4 to the SER and in Section 3.11 of the SER and Supplements No. 3 and No. 4 of the SER.
With the recent emphasis on the availability of postaccident instrumentation (Regulatory Guide 1.97, " Instrumentation for Light-Water-Cooled Nuclear Power Plants To Assess Plant Conditions During and Following an Accident"), the staff reviews evaluate the designs to ensure that control system failures will not deprive the operator of information required to maintain the plant in a safe shutdown condition after any anticipated operational occurrence or accident.
The licensee was requested to evaluate the control systems and identify any control systems whose malfunction could impact plant safety.
The licensee was requested to document the degree of interdependence of these identified control systems and identify the use (if any) of common power supplies, and the use of common sensors or common sensor impulse lines whose failure could have potential safety significance.
This review will be completed by the licensee six months prior to the first refueling outage of San Onofre Unit 2.
The basis for plant operation prior to staff approval of the licensee's review is given in Section 7.7.2 of Supplement No. 4 to the SER.
San Onofre SSER #6 C-7
In addition, IE Bulletin 79-27 (" Loss of Non-Class IE Instrumentation and Control Power System Bus During Operation," November 30, 1979) was issued to the applicant requesting that evaluations be performed to ensure the adequacy of plant procedures for accomplishing shutdown on loss of power to any electrical bus supplying power for instruments and controls.
The results of this review are documented in Section 7.4.3 of Supplement No. 4 to the SER.
Based on the above, the staff has concluded that there is reasonable assurance that San Onofre 2 and 3 can be operated before the ultimate resolution of this generic issue without endangering the health and safety of the public.
A-48 Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment Following a loss-of-coolant accident in a light-water-reactor plant, combustible gases, principally hydrogen, may accumulate inside the primary reactor contain-ment as a result of (1) metal-water reaction involving the fuel element cladding; l
(2) the radiolytic decomposition of the water in the reactor core and the containment sump; (3) the corrosion of certain construction materials by the j
spray solution; and (4) any synergistic chemical, thermal, and radiolytic effects of postaccident environmental conditions on containment protective coating systems and electric cable insulation.
1 Because of the potential for sianificant hydrogen generation, 10 CFR 50.44,
" Standards for Combustible Gas Control Systems in Light Water Cooled Power Reactors," and GDC 41, " Containment Atmosphere Cleanup," require that systems be provided to control hydrogen concentrations in the containment atmosphere following a postulated accident.
The purpose of the requirements is to ensure that containment integrity is maintained and that essential equipment required for safe shutdown of the reactor is able to survive the adverse environment created by a postulated accident.
10 CFR 50.44 requires that the combustible gas control system provided be capable of handling the hydrogen generated as a result of degradation of the emergency core cooling system, so that the hydrogen release is five times the amount calculated in demonstrating compliance with 10 CFR 50.46 or the amount corresponding to reaction of the cladding to a depth of 0.00023 in., whichever amount is greater.
The San'3nofre 2 and 3 design meets current requirements.
The hydrogen control systen it designed to ensure that the hydrogen concentration within the San Onofre 2 and 3 containment is maintained below the lower combustible limit of 4.0 volume percent as specified in Regulatory Guide 1.7, " Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident." The system includes redundant safety grade hydrogen recombiners located inside con-tainment, a safety related hydrogen monitoring subsystem, and a backup hydrogen purge subsystem.
Hydrogen mixing is provided by the containment spray system, the recirculating air cooling units, and the containment internal design that permits convective mixing and prevents entrapment of hydrogen.
The accident at TMI-2 on March 28, 1979 resulted in hydrogen generation well in excess of the amounts specified in 10 CFR 50.44.
As a result of knowing this, it became apparent to NRC that specific design measures are needed for handling San Onofre SSER #6 C-8
larger hydrogen releases, particularly for smaller low pressure containments.
As a result, the Commission determined that a rulemaking proceeding should be undertaken to define the manner and extent to which hydrogen evolution is to be taken into account in plant design.
The NRC published a proposed rule in the Federal Register (46 FR 62281) on December 23, 1981 relating to the analysis of dry containments for large hydrogen evolutions.
l The San Onofre 2 and 3 containments each have a net free volume of 2.3 million
{
cubic feet.
Assuming 30 to 50% metal-water reaction in the core, the resulting i
uniformly mixed concentration of hydrogen in the containment will range from 6 to 10%.
This is well below the concentrations for detonation and even below the limits for combustion with expected steam concentrations in the containment i
atmosphere following a LOCA.
Design pressure of the San Onofre 2 and 3 containments is 60 psig.
Analyses performed on the Zion and Indian Point plants show that the failure pressures are greater than twice their design pressures.
We believe therefore that the failure pressure of the San Onofre 2 and 3 containments is considerably greater l
than the design pressure.
1 I
If a substantial amount of metal-water reaction were to occur shortly following onset of a large LOCA and while the containment is still near its peak pressure, the pressure increase caused by the noncondensible hydrogen gas and its associated exothermic formation energy will be substantially less than the failure pres-sure.
If the metal-water reaction were to occur well after onset of the large LOCA, the containment heat removal system would have condensed much of the steam in the containment and reduced the containment pressure.
This would provide a substantial margin for accommodating hydrogen generated by the metal-water reaction.
A substantial margin would exist for accommodating the hydrogen generated by the metal-water reaction.
At this later time, the containment heat removal system would be able to condense much of the steam in the containment and reduce the containment pressure.
In addition, the short-term lessons learned from the TMI-2 accident have been implemented at San Onofre 2 and 3.
This action will reduce the likelihood of accidents that could lead to substantial amounts of metal-water reaction.
Accordingly, pending resolution of this unresolved safety issue and the rule-making proceeding on hydrogen generation, the staff concludes that San Onofre 2 and 3 can be operated without undue risk to the health and safety of the public.
A-49 Pressurized Thermal Shock Severe reactor-system overcooling events in a PWR that could be followed by repressurization of the reactor vessel can result from a variety of causes.
These include instrumentation and control system malfunctions and postulated accidents such as small-break LOCAs, main steamline breaks, or feedwater pipe breaks.
Rapid cooling of the reactor vessel internal surface'causes a tempera-ture gradient across the reactor vessel wall.
This temperature gradient results in thermal stress, with a maximum tensile stress at the inside surface San Onofre SSER #6 C-9
of the vessel.
The magnitude of the thermal stress depends on the temperature differences across the reactor sessel wall.
Effects of this thermal stress are compounded by the hoop stress i" the vessel is repressurized.
As long as the fracture resistance of the reactor vessel material remailis high, such transients 'will not cause failure.
After the fracture toughness of the vessel is reduced by neutron irradiation, severe thermal transients could cause fairly smalt flaws near the inrur surface to initiate and result in significant cracking.
The vessels of most :oncern are those with high radiation exposure, which are made of material that has a relatively high sensitivity to radiation damage (such as those made witt welds of high copper content).
For the reactor pressure vessel to fail, a number of contributing factors must be present.
These factors are (1) a reactor vessel flaw is of sufficient size to initiate and propagate; (2) a level of irradiation (fluence) and material I
properties and composition is !.ufficient to cause significant embrittlement (the exact fluence is dependent on materials present; that is, high copper content causes embrittlement to occur more rapidly); (3) there is a severe overcooling transient with repressurization; and (4) the crack resulting from the propagation of initial cracks must be of such size and location that the l
vessel fails.
The staff's preliminary review of overcooling events and their probabilities included a study on overcooling events at B&W plants, a survey of operating I
experience on Westinghouse (W) and Combustion Engineering (CE) plants, a review of available accident analyses in FSARs and in vendor topical reports, and a preliminary probabilistic analysis.
The preliminary results of these evalua-1 i tions indicate that there is a probability of about 10 3 per reactor year that i
a B&W-designed plant will experience a severe overcooling transient similar to or worse than that experienced at Rancho Seco on March 20, 1978.
The Rancho Seco transient is the most severe overcooling transient experienced by any PWR in the United States.
The staff estimates that the probability of such an overcooling event in CE-or W-designed reactors is lower, perhaps by an order of magnitude, than for B&W-designed reactors.
This difference is based on design differences and on operating experience.
In the 1978 Rancho Seco transient, reactor pressure was maintained at a fairly high level (1500 to 2100 psig) throughout the cooldown.
The minimum tempera-ture of the reactor coolant (280 F) during the transient was high enough so a
that material toughness of the reactor vessel was not affected.
This evalua-tion leads the staff to believe that if this transient were to be repeated at Rancho Seco or any other B&W-designed facility within the next few years, the reactor vessel failure would still be unlikely.
Nonetheless, the possibility of vessel failure as a result of an overcooling event cannot be completely ruled out.
If an overcooling event such as that at Ranch Seco were to occur, even for the vessel with the most limiting material properties in existence today, the staff would not expect a failure.
The staff conclusion is supported by Oak Ridge National Laboratory analyses of the Ranct Seco event which indicate that the threshold irradiation level (neutron fluence) for crack initiation (that is, small cracks growing to larger ones assuming conservative initial material properties such as RTNDT
- 40 F and San Onofre SSER #6 C-10
2 copper content of 0.35 percent) would be in the range of 1019 neutrons /cm.
. The highest neutron fluence to date in a B&W-designed facility is less than half the minimum value listed above.
It would, therefore, be several years before any B&W-designed facility reaches its threshold irradiation level.
Some reactor vessels in CE and W facilities have somewhat higher fluences; however, other mitigating factors, such as lower values of initial RTNDT provide a significant margin to failure should an overcooling event similar to that at Rancho Sece occur.
4 San Onofre SSER #6 C-11
i APPENDIX D BIBLIOGRAPHY References Section 14 1.
" TORC Code, A Computer Code for Determining Thermal Margin of a Reactor Core," CENPD-161-P, Combustion Engineering, July 1975 (Proprietary Information).
2.
"C-E Critical Heat Flux, Critical Heat Flux Correlation for C-E Fuel Assemblies with Standard Spacer Girds, Part II," CENPD-207-P, Combustion Engineering, June 1976 (Proprietary Information).
I i
3.
"A New Mixed Flow Cluster Dryout Correlation for Pressures in the Range 0.6 - 15.6 MN/M2 (90-2250 psia) for Use in a Transient Blowdown Code,"
Bowring, R.W., " Inst. Mech. Engrs. Conference Publications, pp. 175-182, 1977.
l San Onofre SSER #6 0-1
U S. NUCLE AR REGULATORY CoMMISSloN NUREG-0712 BIBLIOGRAPHIC DATA SHEET Succlement No. 6 1
4 TlTLE AN D SUBTlTLE (A dd Volume No. of worceriate)
- 2. (Leave mek)
Safety Evaluation Report Related to the Operation of 3 RECIPIENT S ACCESSION NO.
San Onofre Nuclear Generating Station, Units 2 and 3
- 7. AUTHOHISI 5 DATE REPORT COVPLE TED l YEAR M ON TH June 1982 l
9 PE HF OHYiNG OHGANIZATION N AME AND M AILING ADDRESS (include 2 0 Code)
DATE REPoHT ISSUED "oNT" lYLAR U.S. Nuclear Regulatory Commission June 1982 Office of !bclear Reactor Regulation 6'""*"*>
Washington, D.C.
20555
- 8. (Leave blana)
- 12. SPONSORING oRG ANIZATioN N AME AND MAILING ADDRESS (include I<a Codel Same as 9. above li. CoNTR ACT No.
t 13 TYPE OF REPORT PE RIOD COVE RE D //nclusive dams)
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- 15. SUPPLEMENTARY NOTES 14_ (t,,,, everj Docket Nos. 506-361 and 50-362
- 16. ABSTR ACT (200 words or less)
Supplement No. 6 to the Safety Evaluation Report for the application filed by Southern California Edison Company, et al for licenses to operate the San Onofre Nuclear Generating Station, Units 2 and 3 (Docket Hos. 5G-361 and 50-362) located in San Diego County, California has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission.
This supplement updates the status of review with regard to certain items that were left unresolved in pre-vious supplements and it evaluates several new review items.
- 17. KEY WoRDS AND DOCUMENT AN ALYSIS 17a. DESCRIPToRS 17b. IDE N TIF IE RSloPE N-EN DE D TE R MS 18 AV AILABILITY STATEMENT
- 19. SE CURITY CLASS (Thss report)
- 21. No. oF P AGES Unclassified Unlimited
- 20. gCgRggS (Ta,s o,ge)
- 22. P RICE N RC F ORM 335 (7 77)
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