ML20023D721
| ML20023D721 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 05/24/1983 |
| From: | Novak T Office of Nuclear Reactor Regulation |
| To: | Tucker H DUKE POWER CO. |
| References | |
| RTR-NUREG-0422, RTR-NUREG-422 NUDOCS 8306020598 | |
| Download: ML20023D721 (44) | |
Text
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NRC PDR L PDR Docket Nos. 50-369 NSIC 50-370 PRC n
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MDuncan RBirkel EAdensam TMNovak Mr. H. B. Tucker, Vice President DEisenhut/RPurple Nuclear Production Department JMTaylor, DRP:IE s
Duke Power Company ELJordan, DEQA:IE 422 South Church Street ACRS (16)
Charlotte, North Carolina 28242
Dear Mr. Tucker:
Subject:
Draft SER Supplement No. 7/ Unit 2 OL Amendment (McGuire Nuclear Station Units 1 & 2)
We have prepared Supplement No. 7 to the McGuire Safety Evaluation Report a
(NUREG-0422). Although SSER No. 7 has not yet been issued, we are herein forwarding a draft copy for your information.
In addition, we have also enclosed a draft full power amendment to the McGuire Unit 2 operating license.
N Sincerely, N'
Thomas M. Novak, Assistant Director for Licensing Division 'of Licensing
Enclosures:
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Supplement No. 7 to McGuire N
Safety Evaluation Report V
(NUREG-0422) Draft 2.
Amendment No. 2 to NPF-17
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. NRC FORM 310 (10 80) NRCM 0040 OFFICIAL RECORD COPY-usce mi-m-em L
e McGui re Mr. H. B. Tucker, Vice President Nuclear Production Department Duke Power Company 422 South Church Street Charlotte, North Carolina 28242 cc: Mr. A. Carr Duke Power Company P.O. Box 33189 422 South Church Street Charlotte, North Carolina 28242 Mr. F. J. Twocood Power Systems Division Westinghouse Electric Corp.
P.O. Box 355 Pittsburgh, Pennsylvania 15230 Mr. G. A. Copp Duke Power Company Nuclear Production Department P.O. Box 33189 Charlotte, North Carolina 28242 J. Michael McGarry, III, Esq.
Debevoise & Liberman
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1200 Seventeenth Street, N.W.
Washington, D. C.
20036 Mr. Wm. Orders Senior Resident Inspector c/o U.S. Nuclear Regulatory Commission Route 4, Box 529 Hunterville, North Carolina 28078 James P. O'Reilly, Regional Administrator U.S. Nuclear Regulatory Commission, Region II 101 Marietta Street, Suite 3100 Atlanta, Georgia 30303 R. S. Howard Operating Plants Projects Regional Manager Westinghouse -Electric Corporation - R&D 701 P.O. Box 2728 Pittsburgh, Pennsylvania 15230
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SAFETY EVALUATION REPORT RELATED TO OPERATION OF-MCGUIRE NUC!.EdR STATION, UNITS 1 AND 2 s,
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-' 4 This report suppleraents the " Safety Evaluation Report Related to the Operation
'of McGuire Nuclear 3tation, Units 1 and 2" (SER (NUREG-0422)) issued in March l-1978 by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Conmission with respect to the application filed by Duke Power Company, as appli-
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cant and owneri for licenses to operate the McGuire Nuclear Station, Units 1 and 2 (Docket Nos. 50-369 and 50-370).
The facility is located in Mecklenburg "7
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~ County, North Carol.ina, aoout 17 mi north-northwest of Charlotte, North Carolina.
t This supplement provides information related' to issuance of a full power authori-
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The staff concludes that the McGuire Nuclear Station can be operated ~by the licensee without endangering the health and safety of the public.
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TABLE OF CONTENTS
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l P_ag ti ABSTRACT.............................................,......*........
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V INTRODUCTION AND GENERAL 4 DI CilSSION............................
1-1 4
1.1 Introduction..............................................
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Q 1.8 License; Conditions.......................................
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- 7 INSTRUMENTA}IONAND.
CONTROLS....................................
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-n 2 ReactorTftpActuationSystem..............................
7.2.5' yReactor Tri p Breake r...................... :.........
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7.8 Environmental Qualification of Electrical Equipment
-Important to Safety.................,.......................
7-1 7.8.1 Introduction and Background.........................
7-1 7.8.3.2 Information Required by 10 CFR 50.49.......
7-2 7.8.3.2.1 Licensee's Responses Addressing Information Required by
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s 7.8.3.3 Aging..................................... "
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- 7. 8. 3. 4 TMI Action Plan EquipmerA...............'*. } ' i 7-5 7.8.3.5 Conclusion...............:...'.............
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22-1 22 TMI-2 REQUIREMENTS.....................................}.......
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3 22.4 NRC Action.......J..,......................
22-1 APPENDICES A
CONTINUATION OF THE CHRONOLOGY OF RADIOLOGICAL REVIEW'0F WILLIAM B.
MCGUIRE STATION UNITS 1 AND 2 OPERATING LICENSE REVIEW B
REFERENCES C
MCGUIRE NUCLEAR STATION SAFETY EVALUATION REPORT CONCERNING THE.
HYDROGEN MITIGATION.
~D MCGUIRE NUCLEAR STATION SAFETY EVALUATION REPORT CONCERNING THE REACTOR TRIP BREAKERS
.McGuireLSSER 7 '
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'l' INTRODUCTION AND GENERAL DISCUSSION I
1.1 Introduction
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On March 1, 1978, the staff of the U.S. Nuclear Regulatory Commission (NRC) 7 issued its Safety Evaluation Report (NUREG-0422) in the matter of Duke Power s
i Company's application to operate the McGuire Nuclear Station, Units 1 and 2.
The Safety Evaluation Report (SER) was supplemented by Supplement Nos. 1, 2, 3, 4, 5, and 6.
On January 23, 1931, Facility License No. NPF-9 was issued to Duke Power Com-pany (licensee and/or applicant) to permit fuel loading, criticality and zero-i power testing of Unit 1.
The license was subsequently revised and amended on June 12 and July 8,1981 to authorize operation at 5% and 100*; of rated power, respectively. On March 3,1983, Facility License No. NPF-17 was is ved to Duke Power Company for Unit 2 authorizing fuel loading, low power testiry for opera-tion at up to 5'; of full power.
The purpose of this supplement is to update the SER by providing additional information related to issuance of a 100*; operating license authorization for Unit 2.
Except where ncted', the material herein supplements material in the SER and
. Supplement Nos. 1, 2, 3, 4, 5 and 6.
Appendix A to this supplement is a con-tinuation of the chronology of principal actions related to the staff's safety
-review of McGuire Nuclear Station, Units 1 and 2.
References cited in this supplement are listed in Appendix 8.*
Appendix C contains the safety evaluation for the hydrogen mitigation sytems. Appendix 0 contains the staff's safety evaluation report on the reactor trip breakers.
Copies of this supplement are available for public inspection at the Commis-sion's Public Document Room at 1717 H Street, N.W., Washington D.C., and at Atkins Library, University of North Carolina, Charlotte, UNCC Station, North Carolina 28223. They are also available for purchase from the sources indicated on the inside front cover of this report.
On the basis of its review, the staff concludes that ' he McGuire Nuclear Station t
Unit 2 may be operated safely up to 100*; of full power in accordance with the Technical Specifications without undue risk to the health and safety of the public.
1.8 License Conditions The staff has identified certain issues in its review that will become condi-tions of the operating license for McGuire Unit 2 when it is issued.
These
- Availability of all material cited is described on the inside front cover of-this report.
McGuire SSER'7 1-1
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i issues are listed below and are discussed further in the sections of this report as indicated.
Issue Sectior.
(1) Environmental Qualification: The licensee shall environ-7.8 mentally qualify all electrical equipment within the scope of 10 CFR 50.49 in accordance with the implementation require-ments of 10 CFR 50.49(g).
(2) Reactor Trip Breakerc:
7.2.5 (a) By June 3, 1983, the licensee shall provide a program plan for conducting a life-test of the undervoltage trip attachment. The life-test program is to be reviewed by the staff before implementation.
(b) The licensee shall modify the design of the automatic shunt trip of the main reactor trip breakers to install an independent fusing scheme. This modification shall be implemented on a schedule consistent with the schedule requirements of the NRC Salem Task Force generic program.
(c) The licensee shall implement the reactor trip breaker and bypass breaker testing as described in Table 1.1.
(d) Within 60 days from the time the full power amendment to the license is issued, the licensee shall provide upgraded post-trip procedures for NRC staff review.
(3) Hydrogen Control Measures (II.B.7): Before startup following 22.4 the first refueling outage, the licensee shall (a)
Install two additional igniter units in the containment lower compartment and four additional igniter units in the containment upper compartment in locations acceptable to the staff.
(b) Provide a means of verifying the operational status of the hydrogen control system in the main control room.
(c) Provide the capability to actuate the hydrogen mitigation system from the control room.
b McGuire SSER 7 1-2
a Table 1.1 Periodic surveillance / maintenance of reacter trip breakers and reactor trip bypass breakers
- Before Each Startup (if not completed Monthly Surveillance (each Every 6 Months within past 7 days) breaker every 31 days)
Surveillance / Maintenance Reactor Trip Reactor Trip and Reactor Breakers Reactor Trip Breakers Trip Bypass Breakers I Functional test of Functional test of UV Response time testing of UV/ **
UV trip device trip device independently break on UV signal from RPS independe,ntly (visicorder shall be used and data trended)
Response time testing of UV/ breaker on UV signal s
-from RPS (event recorders may be used)
Functional test of Functional te't of shunt Trip shaft force measurements **
s shunt trip device trip device independently independently Functional test of UV output force measurement' manual reactor trip from the control Functional test of shunt trip room device independently Ssrvicing/ lubrication / adjust-ment in accordance with manu-facturers recommendations Check the dimensional toler **
ante of pre and post-travel of the trip tab.
Inspect lubricant and cleanliness of Roller Bearing "On failure of 'any reactor trip breaker or reactor trip bypass breaker, either in service or during testing (on either undervoltage or shunt coils), preserve evidence of failure and notify the Commission pursuant to Technical Specifica-tion 6.9.1.10.
- To be performed before and after preventive maintenance f
McGuire SSER 7 1-3 i
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7 INSTRUMENTATION AND CONTROLS L
7.2 Reactor Trip Actuation System l.
7.2.5 Reactor Trip Breaker As a result of failures in early 1983 of the reactor protection tystem (RPS) breakers at several facilities, the Commission issued Office of Inspection and Enforcement Bulletins (IEBs) 83-01 and 83-04 and Information Notice 83-18.
The licensee in response to IEB 83-04 performed tests on the Westinghouse DS-416 breakers used at the McGuire facility.
No failures occurred in these tests. However, subsequent testing resulted in failures of the 05-416 breakers.
These failures were attributed to a variety of causes indicating weaknesses in design and manufacture.
Because of the failures of the DS-416 reactor trip breakers, the staff has reviewed the failure history, the investigative actions taken by the licensee, the licensee's conclusions regarding the causes of the failures, and his main-tenance and test procedures, surveillance program, plant modification to pro-vide automatic actuation of the shunt trip, and the procedures for reactor trip and for anticipated transients without scram.
A summary of the staff's evaluation is presented in Appendix D.
The staff has initiated independent testing of the DS-416 reactor trip breakers at the Franklin Research Center to confirm that all failure mechanisms have been identified.
On the basis of its evaluation and the results of current testing of the device, the staff concludes'that the failure causes have been identified and sufficient remedial actions have been taken to provide reasonable assurance that the McGuire Units 1 and 2 can be operated without undue risk to public health and safety.
However, to increase and improve the reliability of the RPS breakers, the staff will condition the operating license to provide for the licensee actions as discussed in Section 1.8 of this supplement.
7.8 Environmental Qualification of Electrical Equipment Important to Safety 7.8.1 Introduction and Background In Supplement No. 6 (SSER 6) to the McGuire Safety Evaluation Report (SER), the staff identified several open items requiring resolution before 5% of full power is exceeded at McGuire Unit 2.
Subsequently, the staff met with the licensee on March 29 and May 4,1983 to discuss these issues, and by letters dated May 11 and 12. 1983, the licensee provided information addressing these open items.
The staff's evaluation of that information is given herein and rafers to the subsections of Section L8 of SSER 6 that identified these open items.
McGuire SSER 7 7-1 J
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7.8.3.2.1 Licensee's Responses Addressing Information Required by 10 CFR 50.49 By letters datec May 11, 12, and 20, 1983, the licensee provided additional information requirec oy 10 CFR 50.49.
The staff's evaluation of this informa-tion is given below.
7.8.3.2.1.1 Information Addressing Item (1)(b) in Section 7.8.3.2 The licensee has. stated that his. definition of safety-related is consistent with the definition given in 10 CFR 50.49(b)(1).
This open item is satisfac-torily resolved.
.7.8.3.2.1.2 Information Addressing Item (1)(a) in Section 7.8.3.2 inis open. item concerns compliance witn 10 CFR 50.49(b)(2).
The licensee con-i firmed;nis' previous response to this item; tnat is, ne nas not identified any i
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'o nonsafety-related electrical equipment located in a harsh environment whose failure under the postulated accident conditions could prevent satisfactory accomplishment of a safety function by safety-related equipment.
The licensee supplemented the bases for this response with the following information.
As stated in the licensee's May 12 and 20, 1983 letters, the McGuire safety-related electrical power and control systems are designed in accordance with Institute of Electrical and Electronics Engineers (IEEE) Std. 308-1971 and IEEE Std. 279-1971, respectively, as discussed in the McGuire Final Safety Analysis Report (FSAR).
These two standards, as implemented in the McGuire design, place strict requirements on the interfacing of safety-related and nonsafety-related electrical equipment.
Nonsafety related loads receiving power from safety-related buses are automatically tripped from these buses by safety-related breakers, receiving trip signals generated by the plant protec-tion systems, in order to preclude unacceptable influences of nonsafety-related equipment on the safety-related power system.
The McGuire separation require-ments are discussed in FSAR Section 8.3.1.2.7 and have previously been reviewed and accepted by the staff (see McGuire SSER 2).
With regard to control systems where nonsafety-related equipment provides input to control safety-related equipment, accident actuation signals are provided to override the nonsafety-related control inputs.
In addition to the override feature, nonsafety-related inputs to safety-related control systems are reviewed during the design process to ensure that no failure modes of the nonsafety-related inputs can preclude completion of the required safety actuation.
The combination of the override feature and the review of nonsafety-related control inputs ensures that no unacceptable influences of nonsafety-related equipment on safety-related equipment can occur to prevent the satisfactory accomplish-ment of a safety function.
In addition to the design features described above, the licensee performed an analysis of control systems at McGuire in response to Office of Inspection and Enforcement (IE) Information Notice 79-22.
The purpose of the analysis was to determine what, if any, design changes or operator actions would be necessary to ensure that environments caused by high energy line breaks would not cause an electrical nonsafety-related control system to fail in such a manner as to com-plicate the event beyond the assumptions of the accident analysis.
The systems considered in this analysis were identified by Westinghouse for McGuire and re-viewed by the licensee for the interaction described above.
The systems reviewed were the steam generator power-operated relief valve (PORV) control system, the pressurizer PORV control system, the main feedwater control system, and the automatic rod control system.
The results of this review for McGuire revealed that no design changes or operator actions were required to address the issue.
l-The licensee has recently documented the same analysis with the same results for the Catawba Nuclear Station in response to NRC Staff Question 420.3.
The staff has reviewed the information provided and found the Catawba analysis acceptable (see Catawba SER (NUREG-0954)).
The staff finds that the above information from the licensee adequately addresses compliance with 10 CFR 50.49(b)(2); therefore, this open item is satisfactorily resolved.
l McGuire SSER 7 7-3
o 7.8.3.2.1.3 Information Addressing Item (1)(c) in Section 7.8.3.2
)
Regarding the open items identified in this subsection, the licensee stated that the auxiliary feedwater flow transmitters have been replaced with qualified transmitters.
The replacement transmitters are Rosemount 11530 series transmit-ters.
The licensee also stated that failure of the steam relief radiation monitors will not affect the functions of any other safety-related equipment.
This satisfactorily resolves these open items.
7.8.3.2.1.4 Information Addressing Item (2) in Section 7.8.3.2 This subsection identified several items requiring resolution.
Concerning the Robertshaw level switches, the licensee stated that he has replaced these with Magnetrol level switches and has provided justification for interim operation with these switches, pending completion of their qualification, on the basis of the results of recently completed qualification testing, which are being finalized for documentation purposes.
Concerning the in-core thermocouples, the licensee stated that although this instrumentation is currently not safety related, it is a TMI Action Plan item and will be environmentally qualified before startup following the first refueling outage.
Because the thermocouples receive no power, their failure cannot affect any safety-related equipment, and, according to the licensee, the operator will rely on other qualified instruments to provide indication of inadequate core cooling.
This satisfactorily resolves these open items.
The licensee previously had identified McGuire Unit 2 equipment that was not identical to McGuire Unit 1 equipment to be Barton Lot 5 transmitters.
The licensee now states that both Lot 4 and Lot 5 transmitters are used at McGuire Unit 2, and has provided his bases for concluding that the Lot 5 transmitters are qualified because they are similar to the Lot 4 transmitters.
Although the staff has not yet issued the SER addressing Westinghouse Topical Report WCAP-8687, the staff has concluded that the Lot 4 transmitters are qualified.
This satisfactnrily resolves this open item.
The licensee provided additional information concerning the environmental qual-ification of the Rotork Model NA-2 valve actuators and Rosemount Model ll53GA9 pressure transmitters, which were identified as NRC Category II.b items.
On the basis of its evaluation of this information, the staff concludes that these equipment items are qualified for their applications at McGuire. This satis-j factorily resolves these open items.
Concerning NRC Category I.b, II.a, and IV equipment items, the licensee stated that technical resolutions have been determined for the Category II.a items and that documentation of the specific resolutions currently is in progress. Accept-able justifications for interim operation have been provided for equipment lack-ing complete qualification or being replaced.
For the Category I.b and IV equipment items, the licensee stated that qualification documentation is now available in his files for most of this equipment.
For the remaining equipment, acceptable justifications for interim operation or information to resolve the deficiencies have been provided.
The staff considers that this open item has j
been satisfactorily addressed by the licensee.
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McGuire SSER 7 7-4 l
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o 7.8.3.3 Aging The licensee stated that the maintenance and surveillance program for safety-related electrical equipment conforms to guidance contained in ANS-3.2/ ANSI-N18.7-1976, " Administrative Controls and Quality Assurance for Operational Phase of Nuclear Power Plants." This is adequate to resolve this open item at this time.
7.8.3.4 TMI Action Plan Equipment The licensee stated that all TMI Action Plan equipment is installed with the exception of the reactor vessel level instrumentation system, which is to be installed before startup following the first refueling outage, in accordance with a Unit 2 license condition. The licensee also stated that all safety-related TMI Action Plan equipment located in a harsh environment is included in the McGuire equipment qualification program.
In addition, the licensee refer-enced a July 28, 1982 Duke Power Company letter from W. G. Parker to H. R.
Denton, that specifically addressed TMI Action Plan equipment (by item number listed in NUREG-0737). This open item is satisfactorily resolved.
-7.8.3.5 Conclusion On the basis of its evaluation, the staff concludes that all open items identified in Section 7.8 of SSER 6 have been satisfactorily resolved. The staff further concludes that, with the exception of the completion of documentation and the determination of the qualified life or replacement schedule for all equipment, the licensee has demonstrated compliance with 10 CFR 50.49.
However, since the licensee states that all technical resolutions have been determined and because a qualified life or replacement schedule is not important during the early opera-tion of a plant, the staff further concludes that McGuire Unit 2 can be safely operated at 100% full power, pending completion of the environmental qualifica-tion of electrical equipment. The staff will condition the operating license to require the licensee to have all electrical equipment within the scope of 10 CFR 50.49 environmentally qualified by the schedule specified in 10 CFR 59.49(g) that applies to holders of operating licenses issued before February 22, 1983.
McGuire SSER 7 7-5
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22 TMI-2 REQUIREMENTS 22.4 NRC Action II.B.7 Analysis of Hydrogen Control In Supplements 4 and 6 ta the McGuire SER (NUREG-0422), the staff concluded that the interim hydrogen mitigation system (HMS) installed at McGuire Units 1 and 2 is acceptable as an interim hydrogen control measure for degraded core accidents.
However, the staff recommended that the detailed review of the hydrogen mitigation system continue so that a number of issues related to degraded core hydrogen control could be more thoroughly investigated before it endorsed a long-term commitment to deliberate ignition.
This effort was continued by both the licensee and the staff.
The staff has now concluded its review of the matter and has summarized its evaluation of the permanent HMS for McGuire Units 1 and 2 in Appendix C.
The staff concludes that the McGuire permanent HMS is acceptable subject to the installation of two additional igniter units in the containment lower compart-ment and four additional igniter units in the upper compartment and a means of verifying the operational status of the hydrogen mitigation system in the con-trol room.
In addition, the licensee has committed to provide control room actuation of the hydrogen mitigation system. These items shall be implemented before startup following the first refueling outage.
This item has been satis-factorily resolved.
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McGuire SSER 7 22-1
APPENDIX A CONTINUATION OF THE CHRONOLOGY OF THE RADIOLOGICAL REVIEW 0F WILLIAM B. MCGUIRE STATION UNITS 1 AND 2 OPERATING LICENSE REVIEW February 16, 1983 Licensee submits Amendment 71 to application for licenses.
Filing consists of Revision 45 to Final Safety Analysis Report.
February 23, 1983 Letter from licensee responding to 10 CFR 50.49.
February 25, 1983 Letter from licensee concerning results of the preservice examination.
February 25, 1983 Letter from licensee concerning environmental qualification.
February 28, 1983 Letter from licensee forwarding revised Offsite Dose Calculation Manual.
February 28, 1983 Letter from licensee concerning environmental qualifica-tion of electric equipment.
February 28, 1983 Letter from licensee concerning review of reactor trip system.
March 1, 1983 Letter from licensee forwarding annual report.
March 1, 1983 Letter from licensee responding to staff questions.
Mar'ch 1, 1983 Letter from licensee forwarding revi ton to Emergency Plan Implementing Procedures.
March 1, 1983 Letter from licensee concerning 02/03 steam generator design modification.
March 1, 1983 Letter from licensee concerning reactor trip circuit breakers.
March 2, 1983 Letter to licensee concerning proposed Technical Speci-fication change - reduced measurement uncertainty for reactor coolant system (RCS) flow rate.
March 3, 1983 Operating License NPF-17 issued for Unit 2.
License authorizes low power testing and operation at up to but not to exceed 5% of power.
March 3, 1983 Letter from licensee concerning the designated near-site emergency operation facility.
l McGuire SSER 7-A-1
4 March 4, 1983 Board Notification 83 Additional RELAP-5 Calculation for Semiscale S-SR-2 Test.
March 4, 1983 Letter to licensee concerning safety evaluation for environmental qualification of safety-related electrical equipment.
March 7, 1983 Generic Letter 83 Definition of " Key Maintenance Personnel" (Clarification of Generic Letter 82-12).
March 9, 1983 Letter from licensee concerning inadequate core cooling instrumentation systen.
Response to Generic Letter 82-28.
March 9, 1983 Letter from licensee concerning emergency preparedness exercises at Oconee and McGuire Nuclear Stations during 1980, 1981, and 1982.
March 10, 1983 Letter to licensee concerning changes to Safeguards Contingency Plan (two letters).
March 11, 1983 Licensee submits Revision 10 to Emergency Plan.
March 14, 1983 Letter from licensee concerning reduced measurement uncertainty for RCS flow rate.
March 14, 1983 Letter from licensee concerning D2/03 steam generator design modification.
March 14, 1983 SER Supplement No. 6 issued.
March 15, 1983 Letter from licensee concerning the startup testing schedule for Unit 2.
March 16, 1983 Letter to licensee concerning hydrogen mitigation system.
March 16, 1983 Letter to licensee forwarding staff evaluation of utility design review panel report on modification to Westinghouse 02/D3 steam generators.
March 16, 1983 Letter from licensee forwarding Revision 7 to report, "An Analysis of Hydrogen Control Measures at McGuire Nuclear Station,"
March 16, 1983 Letter to licensee providing staff evaluation of Utility Design Review Panel report on modification to Westinghouse 02/D3 steam generators.
March 17, 1983 Letter to licensee concerning proposed Technical Specifica-tion change - reduced measurement uncertainty for RCS flow rate.
March 21, 1983 Letter from licensee concerning environmental qualifica-tion of electrical equipment.
McGuire SSER 7 A-2
March 21, 1983 Letter from licensee concerning methodology for calculating 40 year normal cperating dose rates.
March 21, 1983 Meeting with Design Review Panel to discuss.information related to the forward flush transient on D2/03 steam generators.
March 22, 1983 Board Notification 83 Failure of GE AK-2 Reactor Trip Breakers.
March 23, 1983 Generic Letter 83 Implementation of Regulatory Guide 1.150, " Ultrasonic Testing of Reactor Vessel Welds During Preservice and Inservice Examinations, Revision 1."
March 24, 1983 Generic Letter 83 Transmittal of NUREG-0977 Relative to the ATWS Events at Salem Generating Station, Unit No. 1.
March 28, 1983 Letter from licensee concerning Technical Specification change to reduce the measurement uncertainty for RCS flow rate.
March 28, 1983 Letter to licensee concerning reporting of offsite doses for 1982.
Mart:h 29, 1983 Amendment No. 19 issued to License No. NPF-9 replacing Appendix A Technical Specifications with a revised version which applies to both Units 1 and 2.
March 29, 1983 Meeting with licensee to discuss equipment qualification.
March 31, 1983 Letter from licensee concerning installation of source-range neutron flux instrumentation as an integral part of the standby shutdown system.
March 31, 1983 Letter from licensee concerning IWP/IWV Pump and Valve Inservice Testing Programs.
April 1, 1983 Letter to licensee concerning reactor trip breakers.
April 1, 1983 Letter from licensee forwarding Annual Financial Report.
April 4, 1983 Board Notification 83 Staff Position Regarding Un-resolved Safety Issue A-17.
April 4, 1983 Board Notification 83 Need for Rapid Primary System Depressurization Capability in PWRs.
April 8,1983 Generic Letter 83 Ittegrity of the Requalification Examinations for Renewal of Reactor Operator and Senior Reactor Operator Licenses.
April 13, 1983 Amendment No. 20 to License NPF-9 and Amendment No. 1 to License NPF-17 issued.
Amendments increase the maximum flow rate for the centrifugal charging pumps.
McGuire SSER 7 A-3
April 15, 1983 Letter from licensee forwarding description of various programmatic activities and special audits supporting conclusion that an independent design verification program is unnecessary.
April 15, 1983 Letter from licensee concerning failure of Unit 2 reactor trip breaker "B" to open on an undervoltage trip signal during testing.
April 18, 1983 Letter from licensee concerning reactor trip breakers.
April 19, 1983 Meeting with licensee to discuss undervoltage trip device failures.
(Summary issued April 25, 1983.)
I April 20, 1983 Letter from licensee concerning the removal of the RCS thermal sleeves for Unit 1.
April 22, 1983 Letter from licensee forwarding Revision 8 to report, "An Analysis of Hydrogen Control Measures at McGuire Nuclear Station."
April 22, 1983 Letter from licensee regarding Generic Letter 83-10d concerning resolution of TMI Action Plan Item II.K.3.5,
" Automatic Trip of Reactor Coolant Pumps."
April 26, 1983 Letter from licensee concerning proposed change to Tech-nical Specifications for Unit 1 to reduce the measurement uncertainty for RCS flow rate.
April 27, 1983 Letter from licensee concerning reduced measurement uncertainty for RCS flow rate.
April 28, 1983 Letter from licensee co'ncerning potential boron leaching from the B C pellets encapsulated ir.,the Unit 2 control 4
rods.
April 28, 1983 Letter from licensee concerning actions taken regarding recent problems with the DS-416 breaker undervoltage devices.
April 28, 1983 Letter from licensee concerning reactor trip breakers.
April 28, 1983 Letter from licensee providing additional information on the monitoring and testing program for the steam generators related to the preheater modification.
April 28, 1983 Letter from licensee providing information related to reactor trip breakers.
r May 2, 1983 Generic Letter 83 New Procedures for Providing Public Notice _Concerning Issuance of Amendments to Operating Licenses.
4 May 2, 1983 Letter from licensee concerning problems with reactor trip breakers.
McGuire SSER 7 A-4
May 2, 1983 Letter from licensee forwarding revisions to Crisis Management Plan Implementing Procedure.
May 3, 1983 Letter from licensee concerning reactor trip breaker problems.
May 3, 1983 Letter from licensee identifying additional surveillance that should be performed to ensure the operability of the reactor trip breakers.
May 4, 1983 Board Notification 83 Differing Professional Opinion Regarding Systems Interaction and Safety Classification.
May 4, 1983 Letter from licensee requesting amendments to Technical Specifications to revise the setpoint for upper head injection accumulator automatic isolation.
May 5, 1983 Letter from licensee concerning problem with the Unit 1 Train "B" reactor trip breaker.
May 5, 1983 Letter from licensee forwarding revision to the Emergency Plan Implementing Procedures.
May 5, 1983 Letter from licensee concerning revised rod drop test method and acceptance criteria.
May 5, 1983 Amendment No. 21 issued to License NPF-9 adding a license condition for verifying acceptability of model D2 steam generator design modifications.
May 5, 1983 Letter from licensee providing revised information regard-ing steam generator inspection program following installa-tion of the preheater modification.
May 5, 1983 Letter from licensee concerning loss of electrical load test at Unit 1.
May 6, 1983 Letter to licensee concerning Unit 1 reactor trip breakers and permission for Unit 1 to return to operation.
May 9, 1983 Letter to licensee granting. relief from ASME Code requiring performance of hydrostatic tests after modifications.
May 9, 1983 Generic Letter 83 Integrated Scheduling for Imple-mentation of Plant Modifications.
May 10, 1983 Letter from licensee concerning actions taken regarding recent problems with the 05-416 breaker undervoltage devices.
May 11, 1983 Generic Letter 83 Clarification of Accesss Control Procedu es for Law Enforcement Visits.
McGuire SSER 7 A-5
i'
't l
May 12, 1983 Letter from licensee concerning environmental qualification.
May 13, 1983 Letter from licensee concerning installation of source-i range neutron flux instrumentation as an integral part I
of the standby shutdown system.
May 13, 1983 Letter from licensee concerning installation of reactor coolant system cold-leg temperature monitors as an integral part of the standby shutdown system.
May 17, 1983 Letter to licensee concerning completion of operating license condition 2.C(11)g, " Anticipatory Reactor Trip."
f McGuire SSER 7 A-6 1
APPENDIX B REFERENCES Code of Federal Regulations, Title 10, " Energy" (10 CFR).
Duke Power Company, " Final Safety Analysis Report, McGuire Nuclear Station, Units 1 and 2," Aug. 25, 1974.
U.S. Nuclear Regulatory Commission, NUREG-0422, " Safety Evaluation Report Related to Operation of McGuire Nuclear Station, Units 1 and 2," Mar. 1978; Supplement No. 2, Mar. 1979; Supplement No. 6, Feb. 1983.
--, NUREG-0954, " Safety Evaluation Report Related to the Operation of Catawba Nuclear Station, Units 1 and 2,"
Docket Nos. 50-413 and 50-414, Feb. 1983.
--, NUREG-0737, " Clarification of TMI Action Plan Requirements," Nov. 1980.
--, Regulatory Guide 1.97, " Instrumentation for Light-Water-Cooled Nuclear Power Plants To Assess Plant and Environs Conditions During and Following an Accident," Rev. 2.
U.S. Nuclear Regulatory Commission, Office of Inspection and Enforcement (IE),
Bulletin 83-01, " Failure of Reactor Trip Breakers."
--,Bulletin 83-04, " Failure of Undervoltage Trip Function of Reactor Trip Breakers."
--, Information Notice 79-22, " Qualification of Control Systems."
--, Information Notice 83-18, " Failures of the Undervoltage Trip Functions of Reactor Trip System Breakers."
Westinghouse Electric Corporation, Topical Report WCAP-8687, E01A, Revision 1,
" Equipment Qualification Test Report Barton Pressure Transmitters - Group A (Seismic and Environmental Testing)," Apr. 1982, and E03A, Revision 1,
" Equipment Qualification Test Report Barton Differential Pressure Trans-mitters - Group A (Seismic and Environmental Testing)," Apr. 1982.
Industry Codes and Standards American Nuclear Society /American National Standards Institute, ANS-3.2/ ANSI N18.7-1976, " Administrative Controls and Quality Assurance-for the Opera-tional Phase of Nuclear Power Plants."
Institute of Electrical and Electronics Engineers (IEEE) Std. 279-1971,
" Criteria for Protection Systems for Nuclear Power Generating Stations."
--, 308-1971, "IEEE Standard Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations."
McGuire SSER 7 B-1 G
I APPENDIX C MCGUIRE NUCLEAR STATION SAFETY EVALUATION REPORT CONCERNING THE HYDROGEN MITIGATION SYSTEM i
McGuire SSER 7
i TABLE OF CONTENTS Page C.1 INTRODUCTION.....................................................
C-1 C.2 SYSTEM DESCRIPIION...............................................
C-2 C.2.1 General...................................................
C-2 C.2.2 Igniter Power Supply.....................................
C-2 C.2.3 Igniter Coverage..........................................
C-4 C.2.4 System Actuation..........................................
C-5 C.2.5 Surveillance Testing......................................
C-7 C.3 COMBUSTION / IGNITER TESTING.......................................
C-7 C.4 DETONATIONS AND FLAME ACCELERATION...............................
C-9 C.5 DEGRADED CORE ACCIDENTS AND HYDROGEN GENERATION..................
C-10 C.6 MCGUIRE CONTAINMENT STRUCTURAL CAPACITY..........................
C-11 C.7 CONTAINMENT ANALYSIS.............................................
C-12 C.7.1 Containment Codes.........................................
C-12 C.7.2 Containment Pressure and Temperature Calculations.........
C-13 C.7.3 Confi rmatory Analysis and Conclusion......................
C-14 C.8 SURVIVABILITY OF ESSENTIAL EQUIPMENT C-16 C.8.1 Essential Eguipment.......................................
C-16 C.8.2 Thermal Environment Response Analysis.....................
C-18 C.8.3 Pressure Effects..........................................
C-21 C.8.4 Staff Conclusions Regarding Equipment Survivability.......
C-21 C.9 OVERALL CONCLUSIONS..............................................
C-22 C.10 REFERENCES......................................................
C-23 9
McGuire SSER 7 C-iii
I C.1 INTRODUCTION The staff's licensing requirements relative to the provisions for hydrogen con-trol beyond those prescribed in 10 CFR 50.44 have evolved from numerous delibera-tions among the Nuclear Regulatory Commission (NRC or Commission), the Advisory Committee on Reactor Safeguards (ACRS), the NRC staff, and applicants and licensees.
In summary, the Commission's requirement for ice condenser contain-ments is that a supplemental hydrogen control system be provided so that the consequences of the hydrogen release generated during the more probable degraded core accident sequences do not involve a breach of containment nor adversely affect the functioning of essential equipment.
Based on a determination that a hydrogen mitigation system would provide addi-tional assurance of safety in the event of excessive hydrogen generation result-ing from an accident beyond the design basis for McGuire Nuclear Station, the Duke Power Company (Duke or licensee) installed a distributed hydrogen ignition system in McGuire Units 1 and 2.
The staff concluded in analyses prepared for the Atomic Safety Licensing Board hearings on McGuire Units 1 and 2 that the installed distributed ignition system was acceptable as an interim hydrogen control measure for degraded core accidents.
However, the staff recommended that the detailed review of the distributed ignition system continue so that a number of issues related to degraded core hydrogen control could be more thoroughly investigated b Jore it endorsed a long-term commitment to deliberate ignition.
These issues included items related to combustion phenomena as well as further consideration of a spectrum of degraded core accident sequences.
Based on these recommendations, the operating license of McGuire Unit 1 was conditioned to require that Duke, by the end of the first refueling outage of McGuire Unit 1, provide the bases for a Commission determination that an ade-quate hydrogen control system for the plant is installed and will perform its intended function in a manner that provides adequate safety margins.
In the interim, Duke was required to continue research programs on hydrogen control measures and the effects of hydrogen burns on safety functions.
As part of its research activities, Duke Power in cooperation with Tennessee Valley Authority (TVA) and American Electric Power (AEP) continued to investi-gate alternative measures of hydrogen control.
As a result of continued studies, Duke has concluded that a deliberate ignition system, similar to the interim system, provides adequate safety margins in controlling the consequences of degraded core accidents. The permanent hydrogen mitigation system (HMS) is identical in ccncept to the interim system but provides some system design improvements.
The McGuire Nuclear Station is the second ice condenser plant to have a delib-i erate ignition system as the permanent means of hydrogen control for degraded l
core accidents. The lead plant, Sequoyah, received Commission approval in December 1982 for a permanent hydrogen control system similar to that installed at McGuire.
i McGuire SSER 7 C-1
This report summarizes the staff's evaluation of the permanent HMS for McGuire Units 1 cnd 2.
The staff's review of the HMS has in large part proceeded con-currently with the review of the Sequoyah system.
The staff concluded in its evaluation for Sequoyah that the deliberate ignition system would provide ade-quate margins of safety in the event of a degraded core accident.
The staff's evaluation is documented in Supplements 3 through 6 to the Sequoyah SER (NUREG-0011).
In view of the similarities between the McGuire and Sequoyah system designs and the joint nature of the utility hydrogen research programs, many of the staff's findings for Sequoyah are applicable to the McGuire system as well.
Accordingly, the emphasis of the present evaluation is on those aspects of the McGuire system that differ from those of Sequoyah and on prog-ress in those areas identified in the Sequoyah review as needing further study.
In this report, the staff concludes that subject to the licensee's implementa-tion of certain commitments regarding the location of igniters in the lower and upper compartments of containment and the addition of control room indication of system status, the permanent hydrogen mitigation system at McGuire will per-form its intended function in a manner which ensures adequate margins of safety.
C.2 SYSTEM DESCRIPTION C.2.1 General The HMS is a system of thermal igniters and ancillary equipment Duke has in-stalled within the containment of McGuire Units 1 and 2.
The igniters are designed to ensure a controlled burning of hydrogen in the unlikely event that excessive quantities of hydrogen, well beyond the design bases required by 10 CFR 50.44, are generated as a result of a postulated degraded core accident.
The HMS is designed to promote the combustion of hydrogen in a manner such that containment integrity is maintained.
The HMS is virtually identical to the interim system evalu;ted by the staff in early 1981 (NRC,1981) except for slight modifications in the number and location of igniters.
As in the interim system for McGuire (Duke, Feb. 17, 1981), the permanent system utilizes the Model 7G glow plug manufactured by General Motors (GM) AC Division.
The igni-ter is powered directly from a 120/14V ac tran:;former.
Each igniter assembly consists of a 1/8-in.-thick steel box (8 in. H x 6 in. W x 8 in. 0) which con-tains the transformer and all electrical connections and partially encloses the igniter.
This enclosure meets National Electrical Manufacturers Association (NEMA) Type 4 specifications for watertight integrity under various environ-mental conditions, including exposure to water jets.
The sealed box incorpo-rates a copper heat shield to minimize the temperature rise inside the igniter assembly, and a spray shield to reduce water impingement on the glow plug from above.
In addition, the igniter system is designed to meet seismic Category I requirements.
C.2.2 Igniter Power Supply The igniters in the HMS are equally divided into two redundant groups, with five separate circuits and circuit breakers per group.
The number of igniters on each circuit ranges from 1 to 10.
Igniters located at elevations near the flood level (those in the pipe chase and incore instrumentation area) are on dedicated circuits.
Each group has independent and separate control, power, and igniter locations to ensure adequate coverage even in the event of a single failure.
The system is to be manually actuated from the auxiliary building.
McGuire SSER 7 C-2
.. 7 4
The' igniters are powered from the Class 1E emergency lighting power system that has normal and alternate power supply from offsite sources.
In the event of a loss of offsite power, the igniters would be powered from the emergency diesel generators. Group A igniters receive power from the train A diesels and Group B 2
igniters from the train 8 diesels.
In the course of the Sequoyah hydrogen control system review, the ACRS recom-mended that the staff further consider the need for a backup power supply to ensure hydrogen mitigation system operability in the event of a station black-out. The staff has considered the need for such a backup for McGuire anct con-cludes that the probability of recoverable degraded core accidents involving station blackout at McGuire is sufficiently remote that such sequences need i
l not be made a design-basis scenario for the distributed ignition system.
This
[
conclusion is based on both a qualitative and quantitative assessment of the
[
McGuire power system.
Qualitatively, several features of the McGuire power system should provide an 1
ac power supply system reliability that is better than average.
These features include the location of McGuire in the Duke Power grid, as well as design fea-tures such as immediate, multiple accessibility to the offsite power source, j
instantaneous isolation capability of the switchyard breaker design, and elimi-nation of the fast transfer scheme by generator circuit breakers.
The McGuire Nuclear Station is located in the center of the Duke Power System and is connected to the Southeastern Electric Reliability Council grid by five double-circuit 230-kV and four 500-kV transmission lines.
This is the same grid to which Sequoyah belongs.
Each of the McGuire generating units is pro-vided with two immediate access circuits to the offsite power system.
Each 4
of these two circuits is separate and powered on independent towers from the switching stations to each unit's two stepup transformers.
In addition, there are two interties provided between Unit 1 and Unit 2 power systems at the
,L 6900/4160-V levels so that the two incoming offsite power sources to either unit may be utilized to supply the engineered safety features' loads to the l
cther unit.
a The McGuire switchyard design employs a breaker-and-a-half scheme (three breakers) as opposed to a bus transfer scheme.
The breaker-and-a-half scheme is a simpler and more reliable system because of better automatic isolation capability for certain faults.
The bus transfer scheme requires a series of breaker operations
~ for its transfer scheme to work and also may involve time delays.
t The McGuire design provides two diesel generators per unit, with manual cross-i-
ties which make it possible to use one of the diesels from the other unit to supply emergency loads should both diesels be lost on one unit. The McGuire design also employs-generator circuit breakers, which accommodate certain faults in the region of the generator, and turbine or reactor trips without the need for a fast transfer to an immediate access source. This lack of dependence on fast transfer schemes makes for a more reliable system. 'In addition, McGuire l
has a distinctive design feature, a safe shutdown system with a fifth dedicated
]
' diesel-generator.
Considering the above design features, the staff concludes that qualitatively the reliability of the McGuire ac power supply system should be better than average and should. reduce the likelihood of station blackout at McGuire.
McGuire SSER 7 C-3 x
I*
l' In addition to this qualitative assessment, the staff has considered the prob-ability of recoverable degraded core accidents involving station blackout, including the reactor coolant pump seal loss-of-coolant-accident scenario iden-tified in the Zion and Indian Point Probabilistic Safety Studies.
The staff concludes that the probability of recoverable degraded core sequences involving station blackout is sufficiently remote that such sequences need not be made a design-basis scenario for the distributed ignition system.
This small proba-1 bility is due in part to the relatively short time window following onset of j
hydrogen generation in which ac power must be restored to preclude a core melt.
The probability of restoring power within this window is estimated to be 0.07.
The staff, therefore, concludes that pending completion of Unresolved Safety Issue Task Action Plan (TAP) A-44 on station bla'kout, the safety benefits c
derived from an additional power supply do not warrant the associated costs.
The subject of backup batteries for hydrogen control systems will be addressed in the resolution of TAP A-44; however, preliminary indications are that the findings of this study will reinforce the present conclusion, j
C.2.3 Igniter Coverage i
The hydrogen mitigation system consists of 66 igniter assemblies distributed j
throughout the upper, lower, dead ended, and ice condenser compartments.
Fol-lowing the onset of a degraded core accident, any hydrogen that is produced i
would be released into the lower compartment.
To cover this region, 20 igniters (equally divided between the power trains) have been provided.
Eight of these are distributed on the lower compartment side of the operating deck. Two igniters are located at the top of each of the five steam generat'or and pres-1 surizer enclosures, and another pair is located above the reactor vessel.
Any hydrogen not burned in the lower compartment would be carried up through the ice condenser and into its upper plenum.
Because steam would be removed from the mixture as it passes through the ice bed, thus concentrating the j
hydrogen, mixtures that were nonflammable in the lower compartment would tend to become flammable in the ice condenser upper plenum. Controlled burning in the upper plenum is preferable to burning in the upper compartment because upper plenum burns involve smaller quantities of hydrogen per burn and allow i
for the expansion of the hot gases into the compartment, thereby reducing the l
peak pressure.
Duke has chosen to take advantage of the beneficial character-istics of combustion in the upper plenum and has distributed 12 igniters around i t.
These igniters are located in a staggered fashion alternately between the crane wall and the containment shell wall sides of the upper plenum, at 12 al-most equally spaced azimuthal locations.
i To handle any accumulation of hydrogen in the upper compartment, eight igniters are located in the upper compartment dome. The air return fans provide re-
)
circulation flow from the upper compartment through the dead-ended volume and back into the lower compartment.
To cover the dead-ended region, a pair of igniters is located in each of the eight rooms through which the recirculation flow passes.
In addition, five pairs of igniters are provided in the incore instrumentation area and the pipe chase.
i The staff has reviewed the number and locations of igniters provided in the HMS 1
and finds the igniter coverage acceptable provided additional igniters are in-stalled at lower elevations in the lower compartment, and several of the upper McGuire SSER 7 C-4
- ~
compartment igniters are relocated.to lower elevations in the upper compartment.
The overall objective of this system enhancement is to provide added assurance that combustion of lean mixtures will occur in both the lower compartment and the upper compartment.
Currently, all lower compartment igniters are located at the top of the compart-ment (on the ceiling below the operating floor).
The staff has requested that Duke install additional igniters at lower elevations in the lower compartment to further promote combustion at lower concentrations characteristic of upward propagation. On the basis of its review, the staff concludes that the addition of at least two igniters in the vicinity of the pressurizer relief tank and reactor coolant piping penetrations (elevation approximately 35 ft below the existing igniters) would provide the appropriate lower compartment coverage.
Comparable lower compartment igniter coverage has already been provided in the hydrogen mitigation system installed in the Sequoyah and D. C. Cook ice con-denser plants.
Duke has committed to provide two additional lower compartment igniters at McGuire Units 1 and 2 before restart following the first refueling of each unit.
For operation during the first operating cycle, the present igniter arrangement is acceptable.
The staff also has requested that Duke provide igniters at lower elevations in the upper compartment of containment to reduce the consequences of burning in this compartment. Currently, all of the upper compartment igniters are located in the dome region above the spray headers.
Installation of upper compartment igniters at lower elevations would further promote combustion at lower hydrogen concentrations and provide added assurance that any burning in the upper com-parment will involve smaller quantities of hydrogen.
The staff believes that the placement of four additional igniters at lower ele-vations represents a significant improvement in upper compartment coverage and has requested Duke to make the appropriate modifications.
The Commission has required TVA to provide comparable igniter coverage for the permanent hydrogen mitigation system at Sequoyah. Duke is unable to complete this modification in Units 1 and 2 before the date for Unit 2 startup but has committed to do so before restart followirig the first refueling of each unit.
For operation dur-ing the first fuel cycle, the staff considers the present igniter arrangement acceptable.
C.2.4 System Actuation The licensee's emergency operating procedure for responding to loss-of-coolant accidents (LOCAs) includes instructions for actuating and securing the hydrogen mitigation system. This procedure is to be used by operating personnel after they have taken immediate actions to shut down the plant and diagnose the acci-dent as a loss of coolant.
The first step in the LOCA procedure instructs the operator to verify that all immediate actions in the "Immediate Actions and Diagnostics" procedure have been performed. The next step in the LOCA proce-dure provides instructions to actuate the HMS.
The licensee has determined that the time of actuation will be approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before the first release of hydrogen to containment. As recommended in the interim evaluation, the air handling units used for normal refrigeration in the ice condenser will be tripped for both units for accidents in which the HMS is actuated.
McGuire SSER 7 C-5
The LOCA procedure calls for the HMS to remain actuated (1) for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the establishment of adequate core cooling if any indication of inadequate core cooling exists or has existed or (2) until the containment pressure drops below 0.25 psig if adequate core cooling has always existed for the duration of the transient. The procedure instructs the operator to reactuate the HMS if there is indication of return to inadequate core cooling.
The staff has determined that the LOCA procedure provides instructions to actuate the HMS under all conditions for which it would be needed, and that the instructions for securing the system are based on acceptable conditions.
The HMS is presently actuated by switching a total of 14 breakers at six loca-tions in the auxiliary building.
The postaccident radiation levels in these areas are estimated to be less than 100 mR/ hour, or approximately one-tenth the level at which a specific task evaluation would be performed.
The staff has reviewed the sequence in which the HMS breakers are actuated in the auxiliary building and concludes that the required actions can be completed in a reason-ably short time (less than 10 min).
Although the present switching arrangement affords the operator sufficient time to actuate the HMS for any event in which it would be required, to provide added assurance that the system will be actuated in a timely manner, the licensee has committed to modify the HMS so that it can be manually actuated from the main control room.
This modification will be made for Unitt 1 and 2 before restart following the next refueling of each unit. The licensee also has committed to provide a nieans of verifying the system status from the control room by that time.
The staff finds these changes acceptable.
For operation during the first fuel cycle, the staff considers the present switching arrangement acceptable, provided a number of procedural and other 1
improvements are implemented. As indicated below, each of these items has been discussed with the licensee and he has stated that the necessary improvements will be made for Units 1 and 2 before startup following the steam generator modi-fication outage for Unit 2.
The procedural substeps that provide instructions for actuating the HMS and securing the HMS following termination of safety injection include actions at different locations (motor control center or electrical panels) within the same substeps. No checklist is provided in the procedure for the operator's use in keeping track of his actions while performing the. breaker operations required with the present arrangement.
Some type of placekeeping aid should be provided.
The licensee has stated that the detailed instructions for actuat-ing and securing the HMS will be removed from the body of the procedure and placed in an attachment to the procedure, and that the attachment will provide a separate checkoff space for each breaker.
The staff finds this to be an acceptable means of placekeeping.
Step 3.43 of the LOCA procedure includes two instructions:
(1) secure the HMS and (2) reactuate it upon indication of inadequate core cooling.
The presence of two instructions in one step is undesirable because an operator may believe that the step is completed when one instruction is accomplished.
This is of special concern if the operator is under stress.
The licensee has stated that the procedure will be revised to place these two instructions in separate steps.
McGuire SSER 7 C-6
I In addition, to provide added assurance that the HMS will be actuated upon indi-cation of inadequate core cooling (ICC), the ICC procedure will be revised to provide instructions to actuate the HMS.
In addition to the operational improvements discussed above, the licensee has stated that improvements will be made in the labeling of the HMS breakers at the four lighting panels. To provide added assurance that the proper breakers will be operated to actuate or secure the HMS, these breakers will be labeled distinctively to make them easily identifiable as HMS breakers.
Subject to confirmation that the stated improvements are made, the staff con-cludes that the procedural instructions for operating the HMS are acceptable.
In addition, the emergency operating procedures will be upgraded in accordance with TMI Action Plan Item I.C.1 and " Supplement 1 to NUREG-0737 - Requirements for Emergency Response Capability" (Eisenhut, Generic Letter No. 82-33, dated December 17,1982). The upgraded procedures will address hydrogen mitigation systems. The licensee's program for upgrading these procedures will be reviewed and the procedures will be subject to staff audit.
C.2.5 Surveillance Testing To ensure that the HMS will function as intended, Duke has proposed a surveil-lance testing program similar to that established for the interim system.
Preoperational testing, to be performed before startup, will verify that the electric current drawn by each group of igniters is within tolerance, and that the temperature of each igniter is at least 1700 F.
The current measured in each circuit during preoperational tests provides the baseline for future sur-veillance tests.
The igniter system will be subjected to surveillance testing on a quarterly basis. This testing will consist of energizing the HMS and taking current and voltage readings of the igniter circuits at the emergency lighting panelboards.
If the power consumption does not compare favorably with that measured during preoperational testing, the igniters on the affected circuits will be individ-ually inspected to ensure their operability.
In addition to power consumption measurements, the igniter temperatures will also be measured at specified intervals.
C.3 COMBUSTION / IGNITER TESTING In support of the interim distributed ignition system, Duke, TVA, and AEP con-ducted two testing programs to obtain information pertinent to the performance characteristics of the glow plug igniters. A summary discussion of igniter testing was provided in Supplement 6 to the Sequoyah SER. The staff concluded in its review of the Sequoyah system that the results of the utility combustion testing programs support the use of a distributed ignition system for post-accident hydrogen control.
Although staff findings regarding the deliberate ignition system were favorable, the issue of igniter performance in a spray environment remained an open item in the staff's final evaluation of the Sequoyah hydrogen control system. This was due primarily to the fact that the Tayco igniter used in the Sequoyah system (1) exhibited a tendency to cool significantly in the spray environment and i
McGuire SSER 7 C-7
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e
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(2) was never combustion tested in a spray environaent.
Furthermore, what Spray ~
tests were conducted with this igniter failed to simOate adequately importint t
characteristics of the spray environm'ent, such as sprapidroplet flux.
- Tinse, s
factors led the staff to require addityonal c, testing for the Tayco igniter.'
\\
l TheMcGuiresystem1sesaGMglowp'hy gnNchratherthantreeTaycoign'if.er.
With regard to testing of the glow plug in'a spraywn'dr3rcar4'sLpsort. of the w w ous tests have been performed as.part of bothltarly t.est 9g M t Fenwai in interim system and the utility hydrogen resehrcti program'cenducted during the
~
past 2 years.
In all tests','the glow plug succashfully,infl lated combustion N
'y V
% Q1 in a spray, environment.
's s
In the Fenwal tests, a holicw.cuneiozzle #th,145-degrg half angle was installed at the top of the 6-fiddialetyrisf.,5eripal testv e m l; a glow plyg g igniter was located at the.' center of b sphe.% Static tustsswith hydrogen w m concentrations of 6% and SX, ;aChel(ashrim.iedt tests, were 'conduc'ted!
These ?
tests indicated the Affects, of spray Roerati6Nn igniter performanca th b;'
minimal in terms of afffcting 'the abliny of the ioniter to f nitiate' combustion.
However, with the hollow cone 3nzjle-used, it is likely thatlajafga' fractiiin of the spray passed throuah the Mripad "of the spray cone and ran down the.
c
/
vessel wall, rather thanifa[lingivsttid411y'through the vessel atqsphere.
(9,,,
spray density was not measuted in these-fests, trd Fenwal tests by themselvg i '~
are considered inconclusive'with regardste the ef tsct pf ths 5priy on igniter' performance.
S l
s
-~
a -;
.s i -
w Additional spray tests were conducted by Factory Mutuc1 (FM) and Mcurel as part' of the utility research program.
The FM test prograd investi$ated3he' effects' s
of water fog density, droplet Jiameter, and temperature on t q loe r flamra-D bility limit of hydrogen-air mixtces; the Acurexgyogram addresed the, effects t
- (.
of fog and sprays on the characteristics of deflagratisn at?arger scale.
The N'
.1 resultsoftheseprogramsarediscussedinSup).lementjtoyheSequoyah.SER.
l*""
nN n As part of the FM test program,13 tests were condudEedNith the glow plug t4ing differentspraynozzlestoachievearangeofsprd/cincitlons.
The" droplet S '
sie size, droplet distribution, and spray flux present ia -the ignition tube we.re;%
D' measured in the FM tests.
From this information'ani ~ consider 3t{on of droplet
\\
3 fall velocities, spray density was datarmined.
Ettimated spray conditions' s
investigated ranged from a spray density (water, volume if% action) of 2 X 10 5
'with a volume mean droplet diameter of 10 p to' t. density of 1 X c10 2,with a);
mean droplet diameter of 100 p.
Spray flux at\\ab orizontal piane in the vessel ranged from 0.04 to 0.23 gpm/ft.
An unshielded glow plug successfully initi-2 ated combustion in all tests.
The staff has compared the spray environment in<the FM tests with that expected in the upper compartment of the McGuire containment. The McGuire upper com-partment environment can be characterized by a spray density of approximately 2
2 X 10 4, a mean droplet diameter of 700 p, 'and a spray flux of 0.65 gpm/ft.
Thus, the FM glow plug tests bound the spray density expected in containment but underestimate the spray flux and drop)et size.
i x
In addition to the FM tests, a number of-spray tests were also conducted in the thesametypeasthatinstalledinNcGuire;thus'Scpce'rrp,neludedanozzleof Acurex test vessel.
Spray nozzles investigated at Acurex i RSgarding droplet, NN
,s No
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McGuire SSER 7 C-8 so i
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e
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,size effectt w c hile p3te'd.,'The glow plug'successfully initiated combustion inalltestyteowever,Tcpprtentcharacteristicsofthesprayenvironmentsuch as spray dcopiet djnsity@d spray flux were not quantified in these tests.
,g y
In spite of the ahparent Shortcomings of< many of the spray tests, the range of sprav mnditionginvestigated with the-glow plug resulted in a significant variEttoWn several importht spray parameters which influence igniter cooling and operabiljty), e.0, A pl'et spray temperature and spray flux.
Although any 4
one test' might be cor1Mdre-d inadequate with regard to some spray parameter or lack of a particurar tesi ireapurement, the body of data taken as a whole sup-po'rts the use oL thq'gb.Pp,1us igniten The fact that combustion was initiated in 'all cases providet, ass'lJrance that the glow p1Lg will operate as intended in
' p spray'envinnment> Additione.l.Wsurance is provided by the igniter spray
,..shind (not : valuated in.the aforementioned tested but installed on each igni-
, h ;tj,7 pt:gMrom dOover,4.The staff inte'nds'to further investigate the e M!e >Hembly in tv plant), which,will \\raduce water impingement on the glow
'Q' y
on' igniter operability as part of
- s. ongoing hydrogen research program at
%,Sandia but_ finds tha_t the3 glow plu cwtiustion tests conducted to date provide an,piegliate basis for use'.cf the glbw plug igniter in the permanent hydrogen
, mitig:. tion syitem st'McGuire.
\\
Lm N C A, DETONATIONS AND FLAME ACCELERATION 3
As discossed in Supplement 6 to the Sequoyah SER, a series of large-scale mix-
~ing tests was cMiucted by the Hanford Engineering Development Laboratory (HEDL) as part of the Electric Power Research Institute (EPRI) research program. Test results show that good mixing in the lower compartment can be expected if the air return fans remain operational thoroughout the acciacat.
In all cases with forced air recirculation, which included two jet orientations and two different release rates, the maximum concentration difference between all points in the test compartment +as less than 3 volume percent at all times and was generally on the order of 21 The upper compartment of containment is also expected to be well mixed' because of operation of the containment spray system. On the basis of its review of the HEDL results, the staff concludes that the formation j
o{ gsigni g tliydrogen concen'tration gradients in containment is unlikely.
With rec beh tMa potential for local detonations, operation of the deliberate b ignition system in conjunction with the nixing by the air return fans ensures that hydrogen coacentrations throughout containment will not approach those
q limits necessary to support detonation for the duration of the accident.
In i
this regard, the formation of detonable pockets of hydrogen should be precluded.
Even' assuming that a ti@ concentration might be formed locally, detonation of the 66Dd by a glow pag igniter is unlikely because these igniters are generally acknowledged to be unsuitable as direct initiators of a detonation.
This con-clusion that detonation'will not occur is supported by test data, including several of the tests recently conducted at Whiteshell and Lawrence Livermore National Laboratory (LLNL). Although these tests do not show conclusively that detonation or transition to detonation cannot occur, they do illustrate the
'dffficulty involved il producing the phenomenon even when~using stoichiometric hydrogen-air ' ixtures.
m Another cor.cern related to the detonation issue is that of flame acceleration.
The phenomenon of flame acceleration as a possible mechanism for producing a
+'7, s
),
McGuire SSER 7 C-9
,j
i detonation or large overpressures in containment and the staff's position on this matter were discussed in Supplements 4, 5, and 6 to the Sequoyah SER.
As discussed in Supplement 6 to the Sequoyah SER, the staff has previously considered these matters and concluded that flame acceleration poses no threat to the containment.
Additional tests are planned at both McGill and Sandia to address such topics as the effects of steam addition and scaling on the requisite hydrogen concen-tration for flame acceleration.
A substantial portion of this work will be conducted in the FLAME facility and the heated detonation tube at Sandia as part of the NRC hydrogen research program.
Results of these programs should become available in mid-to-late 1983. The staff believes, however, that the findings to date by McGill (Berman, 1982) will not be significantly altered by the additional tests and that they provide an adequate basis for its con-clusion tnat detonations will not occur.
Even though investigations show detonable mixtures of hydrogen will not be formed as a result of a postulated degraded core accident at McGuire, Duke has calculated the response of the containment shell to a postulated local detona-tion of a 6-ft-diameter gas cloud adjacent to the containment shell.
The results of this analysis showed that the calculated local stresses were well below the actual material yield strengths, and within the allowable limits as specified by the American Society of Mechanical Engineers, " Boiler and Pressure Vessel Code" (ASME Code).
At the request of the staff, Sandia has performed independent calculations of the effects of various postulated local detonations on the containment struc-ture using the CSQ computer code in conjunction with a detailed structural model.
Results of conservative calculations for the upper plenum of an ice condenser plant indicate that the containment would survive upper plenum detonations. Additional detonation calculations for other regions in contain-ment are planned to improve the staff's understanding of the consequences of local detonations and to better assess safety margins. As previously stated, however, it is the view of the staff that the conditions that must prevail to produce detonations are extremely unlikely.
Moreover, even with the presence of detonable mixtures, as assumed in the the Sandia analysis, there has been no demonstration that a detonation could be initiated.
As the results of the Sandia investigation are not expected to alter the staff's findings on the hydrogen control capability at McGuire, this effort is viewed as confirmatory.
C. 5 DEGRADED CORE ACCIDENTS AND HYDROGEN GENERATION As discussed in the staff's analysis of the interim system, a small-break LOCA followed by a failure of emergency core cooling injection (S 0) was selected 2
by Duke as the base case for evaluation of the hydrogen mitigation system.
Hydrogen release rates for this scenario are a time-varying function whose average is about 20 lb per minute.
The staff considered these rates to be representative of releases that might be encountered in typical degraded core accidents and considered them an acceptable upper limit basis for use in the interim evaluation.
However, for purposes of the final evaluation the staff requested Duke to broaden the studies of steam and hydrogen releases to account for a number of uncertainties in the analysis. Among these were the possibility McGuire SSER 7 C-10
o l
that (1) other scenarios might present schedules of steam and hydrogen releases not covered by the analysis chosen; (2) steam inerting might occur at some time during the sequence allowing large concentrations of hydrogen to develop; (3) the recovery period mignt produce an exceptional burst of steam or hydregen; or (4) hydrogen might be released after the loss of-the ice heat sink.
In the follow-on CLASIX studies that were submitted by Duke (Parker, Oct. 30, 1981),
hydrogen releases were varied to correspond to higher release rates (260 lb per minute) and releases after the ice had melted.
The staff has compared the release rates and sequences used in Duke calculations with those developed in an independent study of degraded core accidents in ice condenser plants carried out at Brookhaven National Laboratory (Yang and Pratt, 1982).
It is clear from this comparison that Duke's choices of hydrogen and steam release rates cover the above range of accident scenarios.
The highest rate of hydrogen release calculated by Brookhaven was about 60 lb per minute.
The Brookhaven calculations did not indicats that these rates would be exceeded during quenching or recovery from the degraded core conditons as well as in the initial core uncovery phase.
In addition, the staff has compared the release rates chosen by Duke with those anticipated in the Interim Rule on hydrogen control.
(The 1000-lb per-minute maximum suggested in the proposed rule is considered to be overly conservative and will likely be reduced to about 150 lb per minute in the final rule.)
In this comparison, the release rates used by Duke were again found to be an ade-quate represer.tation of the scenarios considered important in these degraded core situations.
The staff, therefore, finds the Duke treatment of scenarios to develop steam /
hydrogen source terms to be in confermance with the anticipated requirements of the Interim Rule on hydrogen control for degraded core accidents.
C.6 MCGUIRE CONTAINMENT STRUCTURAL CAPACITY In support of the licensing of the McGuire plant, the ultimate pressure-retaining capacity of the McGuire steel containment was calculated by the staff's con-sultant, Ames Laboratory (NUREG/CR-1891).
The calculations indicated that the steel containment has a mean ultimate capacity of 84 psig. To provide an ade-quate safety margin, the staff reduced its mean ultimate value of 84 psig by three standard deviations.
The standard deviation computation incorporated ths variations in the material properties, material sizes and thicknesses, stiffener spacing, and containment shell diameter.
The standard deviation of the contain-ment pressure was calculated to be 12 psig.
Therefore, the ultimate capacity of the containment adopted by the staff was 48 psig.
An assessment of the con-tainment penetrations was also made by the licensee which indicated that the pressure capacity of the penetrations is greater than that of the containment shell.
Thus, the penetrations are not the controlling item for the containment pressure capacity.
The licensee has also made an evaluation of the reinforced concrete floor that divides the upper and lower compartments (operating floor).
This evaluation showed the reinforced concrete floor differential pressure capacity to be 41 psi.
The staf f consultant computed the value of the internal pressure which would produce stresses in the steel shell corresponding to Service Level C limits as McGuire SSER 7 C-ll l
A specified in the ASME Code,Section IV, Division 1.
This value is 38 psig.
This value is based on the finite element analysis model used in computing the containment ultimate capacity reported earlier.
The limiting section in this analysis is the 3/4-in.-thick cylindrical plate.
Duke independently computed the ASME Code Service Level C internal pressure, based on his containment shell panel mooel, and reported this value to be 45 psig.
On the basis of'the con-sultant's analyses and the licensee's analyses, the staff concludes that the estimated pressure retention capability for ASME Code Service Level C limits is 38 psig with all of the inherent safety margins of the code implied.
The Interim Kule on hydrogen control will permit some flexibility in the method used by the licensee to demonstrate containment structural integrity.
As pro-posed, acceptable methods would include (1) the use of actual material proper-ties with suitable margins to account for uncertainties, which results in the calculated value of 48 psig for the McGuire containment, or (2) the use of ASME Code Service Level C limits, which results in a value of 38 psig for McGuire.
Containment analyses discussed later indicate that for McGuire, the containment pressure response to a postulated hydrogen burn event will remain below either pressure value throughout the transient.
C.7 CONTAINMENT ANALYSIS C.7.1 Containment Codes Calculations of containment atmospheric pressure and temperature have been per-formed using the CLASIX computer code developed by Westinghouse Offshore Power Systems (Westinghouse OPS-36A31). Descriptions of the CLASIX code have been previously reported in Supplements 3 through 6 to the Sequoyah SER.
As part of the McGuire Unit 1 license condition, the staff asked for improved calculational methods for containment pressure and temperature response to hydrogen combustion.
Specifically, the staff requested that CLASIX be refined to permit the simulation of structural heat sinks and the separate modeling of the upper plenum.
The present and latest version of CLASIX incorporates these changes.
In addition, the staff requested further verification of the CLASIX code by comparison with esults from other accepted codes and combustion tests.
To increase the level of confidence in the CLASIX code, the licensee has com-pared calculated results from CLASIX with the calculated results of the Westing-house C0C0 CLASS 9 code (Westinghouse, 1981), the Westinghouse Transient Mass Dis-tribution (TMD) code (WCAP-8077, -8078), and the measured results of selected Fenwal and LLNL tests. A more detailed discussion of the CLASIX code, verifica-tion efforts, and staff review is provided in Supplement 6 to the Sequoyah SER.
Additional confirmation of the CLASIX code has been prri ded by means of a gen-i eric hydrogen combustion code currently under developmeqt at Sandia as part of the NRC hydrogen research program.
The Sandia HECTR (hydrogen event:
contain-ment transient response) code is comparable to CLASIX and COMPARE in terms of analytical capabilities for ice condenser plants, but will in future versions provide for more detailed treatment of mixing, transport, and flame propagation than the present codes permit.
Preliminary HECTR analyses for the Sequoyah base case are in good agreement with the results of CLASIX and COMPARE analyses.
McGuire SSER 7 C-12
C.7.2 Containment Pressure and Temperature Calculations The approach taken by Duke to establish the acceptability of the hydrcgen miti-gation system was to select an accident sequence based on its significance and.
characteristics from the standpoint of hydrogen threat, and then to vary key aspects of the containment analysis parametrically.
This is the same approach used by TVA in the licensing of Segouyah.
As in previously reported analyses, a small-break LOCA with failure of safety injection, the S D event, was chosen 2
as the base case.
Duke has performed calculations of the containment pressure and temperature response to the base case scenario using the latest version of CLASIX and the releases calculated from the MARCH code.
For the base case cal-culation, Duke assumed a lower flammability limit of 8.5 volume percent hydro-gen, complete combustion, and a flame speed of 6 fps.
Test data from Fenwal and Whiteshell, as well as the literature on combustion, indicate that ignition in the turbulent postaccident environment will occur around 5 volume percent hydrogen.
The assumption of ignition at the higher concentration results in a greater amount of energy being released over a shorter period of time, and thus is conservative. Another conservatism in the CLASIX analysis is the assumption that ignition will occur simultaneously at all igniter sites in a compartment.
This assumption will act to further increase the calculated pressure and temperature.
lhe results of the CLASIX base case analysis indicate that the hydrogen will be ignited in a series of 6 burns in the lower compartment and 23 burns in the upper plenum.
The burns. occur over a 2500-sec interval, with the 6 lower com-partment burns intermixed, some concurrently, with 13 upper plenum burns over the first half of the interval.
The peak calculated containment pressures and temperatures are 12.5 psig and 1358 F for the lower compartment, 12.5 psig and 255 F for the dead-ended region, 12.6 psig and 1526 F for the upper plenum, and 12.0 psig and 173 F for the upper compartment.
The peak differential pressure across the operating floor is approy.imately 2 psi, with the higher pressure occurring in the upper compartment. The pressure in containment before the first burn was approximately 6 psig.
As a result of the action of engineered safety features such as the ice conden-ser, air return fans, and upper compartment spray, the pressure and temperature spikes were rapidly attenuated between burns. After the last hydrogen burn, which occurs at approximately 7000 sec into the accident, roughly 1.1 x 106 lb of ice are calculated to remain in the ice condenser section (representing at least 150 x 106 Stu in remaining heat removal capacity).
In summary, the results of the Duke base case analysis show an increase in con-tainment pressure as a result of hydrogen burns of about 7 psi, with the con-tainment remaining well below the lower bound ultimate capacity of 48 psig.
The analysis predicts that burning will occur in the lower compartment and the upper plenum, thereby gaining the advantage of heat removal by the ice bed and venting to the large upper compartment volume.
It should also be noted that each burning cycle involved the combustion of only 35 lb of hydrogen or roughly 2 x 106 Btu of energy addition.
By burning at a given concentration in the lower compartment and upper plenum, there is also the advantage of burning less total hydrogen at a time because the combined volume of these compartments t
accounts for less than one-third of the total containment volume.
McGuire SSER 7 C-13 l
i
In addition to the base case, Duke has performed sensitivity studies to assess the effects of partial operatior of the containment air return fans and sprays, heat removal by ice, and hydrogen release rates.
Finally, the effect of such postulated phenomena as fogging reducing the burn completeness in the upper plenum and steam inerting the lower compartment were analyzed by Duke.
The results of selected CLASIX sensitivity analyses are summarized in Table C.1, along with the results predicted by Los Alamos National Laboratory (LANL) using the hydrogen burn version of the COMPARE code.
In all cases analyzed, the peak containment pressures calculated by either code are well below the ultimate containment pressure capacity of 48 psig and are typically below the contain-ment design pressure of 15 psig.
It should be noted that the calculated peak pressures reported for the McGuire sensitivity cases are generally lower than comparable results for Sequoyah.
This is attributed primarily to the fact that a flame speed of 2 fps was assumed in the McGuire sensitivity analyses in con-trast to the more conservative value of 6 fps used in the Sequoyah analyses.
Peak pressures obtained using a 6-fps flame speed are expected to be somewhat higher but still well below the containment pressure capacity.
Also, peak pressures and temperatures predicted using the early version of CLASIX are con-servative because this version does not take credit for radiation heat transfer from the flame and heat transfer to passive heat sinks.
The results of the CLASIX sensitivity analyses demonstrate that a wide variation in assumptions still results in acceptable containment pressures.
It should t'e noted that the case: with no ice are not mechanistic; i.e., they are not repre-sentative of the 5 0 scenario.
However, these cases importantly demonstrate 2
that, even without ice, the containment pressure with the assumed igniter opera-tion remains below the containment pressure capacity.
This serves to indicate some insensitivity to whatever accident scenario is chosen.
C.7.3 Confirmatory Analysis and Conclusion At the request of the staff, LANL has performed confirmatory analyses for the base case and several other cases using the hydrogen burn version of the COMPARE code (NUREG/CR-3278). Agreement between COMPARE and CLASIX analysis of the base case transient was good, with COMPARE predicting a peak containment pressure of 15 psig and peak differential pressure across the operating floor of 3 psi for the base case.
More exhaustive comparisons between CLASIX and COMPARE were not pursued for McGuire because detailed comparisons performed for Sequoyah (described in Supplement 6 to the Sequoyah SER) indicated good agreement between the two codes.
Although the Duke sensitivity studies indicate that containment integrity will be maintained for the base case and all sensitivity variations considered, upper compartment burns occurred in only a few cases, and in those cases a flame speed of 2 fps was assumed. The subject of burning in the upper compartment was pre-viously identified as a staff concern in the review of the nydrogen mitigation system at Sequoyah.
Staff interest in this area lies in the fact that ignition in the large, relatively open upper compartment conceivably represents the largest energy release rate by combustion and thus the greatest threat to con-tainment.
As a result of these considerations, the staff required TVA to install additional upper compartment igniters in the permanent hydrogen mitiga-tion system at Sequoyah to ensure smaller burns in this region.
Although the McGuire SSER 7 C-14
Table C.1 Containment sensitivity studies
- Calculated peak Calculated peak pressure (psig) temperature ( F)
LC UC LC UC Base case 12.5 12.0 1358 173 (14.4)
(15.1)
(1542)
(215)
Flame speed 1 fps flame 9.4 9.4 717 135 2 fps flame 11.8 11.6 1138 162 Safeguards 1 fan,1 spray operation 12.7 12.7 1100 175 No ice 19.2 19.2 1167 407 Hydrogen release 4 x base case H2 release rate 10.4 10.6 1193 164 Reduced igniter performance Inerted LC 10.3 10.6 225 160 Inerted UP 14.4 14.4 1250 388 LANL mechanistic burn model Conservative (30.8)
(29.5)
(1563)
(542)
Best estimate (23.9)
(24.1)
(1458)
(377)
- LC = lower compartment; UC = upper compartment; UP = upper plenum.
All sensitivity cases assume base case parameters and 2-fps flame speed except as noted;
(
) = results predicted by LANL using hydrogen burn version of COMPARE.
Duke upper compartment burns did not result in excessive pressures, the staff asked LANL to investigate this phenomenon further for McGuire.
In response to the NRC request, LANL performed a number of additional sensi-tivity analyses using the modified COMPARE code.
The approach taken by LANL was to identify the combination of burn parameters required to produce the maximum containment pressure and then to assign parameter values based on a mechanistic burn model that is substantiated by test.
Independent burn initia-tion in the upper compartment was identified as necessary to produce maximum pressures.
The model used by LANL to establish parameter. values for the COMPARE contain-ment analyses is based on estimates of turbulence levels and fluctuations, and McGuire SSER 7 C-15 y
their relationship to eddy diffusivity and burn velocity.
Specifically, the controlling rate mechanism for the transport of the hydrogen from its source to an igniter can, in general, be estimated by using turbulence theory.
The rate of burning for the lean mixtures under consideration is also controlled by the turbulence level. The level of turbulence can then be estimated by summing all of the dissipation sources (sprays, fans, jets, natural convection, etc.) and by using the formulation that relates the turbulent kinetic energy, mixing length, and eddy diffusivity to the rate of dissipation of kinetic energy.
The tur-bulence model was used to estimate the mean concentration at the initiation of burning, and the flame speed for the ice condenser containment burn analyses in which the first burn occurred in the upper compartment.
TwoCOSPAREcalculationswereperformedforMcGuiretoassessthesignificance of upper compartment burning.
Burn parameters for these runs were specified so that burning could only initiate in the upper compartment but could propa-gate into any compartment in which the hydrogen concentration is greater than 4.1 volume percent.
The first COMPARE run assumed ignition at 5% hydrogen with 40% burn completion and a flame speed of 30 fps. The second run assumed the best estimates for these parameters based on the mechanistic burn model, i.e.,
ignition at 4.2% hydrogen with 10% burn completion and a flame speed of 16 fps.
Results of these calculations, summarized in Table C.1, show that for both cases peak pressure will remain below the pressure capacity of the containment.
The peak differential pressure across the operating floor was calculated to be ap-proximately 10 psi for these cases. A structural analysis of the containment air return fans shows their pressure differential pressure capability to be well in excess of this value.
The staff cancludes that the CLASIX containment analysis performed by Duke and confirmed in part by LANL provides an adequate basis for concluding that hydro-gen combustion associated with the operation of the HMS will not pose a threat to the integrity of the McGuire containment.
The staff, however, intends to continue its evaluation of tha code as part of its ongoing code assessment work and licensing of hydrogen control system for other plants.
C.8 SURVIVABILITY OF ESSENTIAL EQUIPMENT Although the HMS is designed to prevent high hydrogen concentration buildup by deliberate ignition of relatively low concentrations of hydrogen in hydrogen-air-steam mixtures, the resulting release of thermal energy may still be suf-ficient to significantly increase the temperature of the equipment located in the containment.
Because some of this equipment is needed to ensure main-l tenance of the safe shutdown condition and of containment integrity, Duke was required to demonstrate that the essential equipment located inside the contain-l ment will survive the hydrogen burn environment resulting from operation of the i
HMS.
Duke has determined analytically the thermal response of selected pieces of essential equipment exposed to a hydrogen burn environment and demonstrated the survivability of the equipn.ent by comparing the resulting temperatures with the qualification temperatures for this equipment.
C.8.1 Essential Equipment The licensee provided a list of the equipment which has to survive a hydrogen burn based on its function during and after an accident.
In general, all the I
McGuire SSER 7 C-16 i
1 equipment located in the containment and belongincj to the safety-related systems was considered essential for the safety of the plant.
The list of the equipment identified by the licensee as essential to achieve and maintain a safe shutdown condition for the reactor core and to maintain containment integrity is provided in Table C.2.
Table C.2 List of essential equipment Steam generator water level transmitters Pressurizer water level transmitters Reactor coolant loop resistance temperature detectors (hot and cold leg)
Core exit thermocouples Containment air return fans Hydrogen skimmer fans Hydrogen igniters Associated power and instrument cables Hydrogen recembiner PORV and block valves Penetrations The staff compared the licensee's list of essential equipment with the list pre-pared independently by the staff and finds that the licensee's list contains all the equipment essential for safe shutdown of the plant under accident conditions.
Duke has reviewed the list of the equipment for components which, because of low heat capacity, heat-sensitive components, or location in containment, would be more susceptible to thermal damage than other items in the list. Duke re-stricted the analytical survivability evaluation to the equipment which is most sensitive to temperature change, the rationale being that if the most suscep-tible items on the list are shown to have a reasonable assurance of surviving a degraded core event, these evaluations will bound all other items on the list.
On this basis, Duke has reduced considerably the number of thermal response analyses that has to be performed.
The following equipment items were selected for an evaluation of their response to the hydrogen burn environment:
(1) igniter assembly (2) igniter power cable (3) Barten transmitter (4) thermocouple cable (5) resistance temperature detector (RTO) cable (licensee supplied)
(6) RTD cable (vendor supplied)
The staff has reviewed the criteria used by the licensee in selecting the equip-ment for analytical investigation. The staff concludes that determination of the survivability of these pieces of equipment will be sufficient for establish-ing survivability of all the equipment listed in Table C.2 provided the licensee has (1) included all equipment h Table C.2 in his equipment qualification (EQ) program or (2) orovided separate. bases foi' establishing survivability limits for the equipment not in the program. The licensee has met these provisions for all' essential equipment.
McGuire SSER 7 C-17
m__
1.
l 1.
l-C.8.2 Thermal Environment Response Analysis The thermal environments used for evaluating equipment survivability were deter-mined by the licensee based on either analyses using the CLASD.. computer code or analysis of heat transfer in the vicinity of a flame.
CLASIX temperature profiles were developed assuming the base case code input parameters with varia-tions in flame speed.
Analytical determination of the thermal environment was based on consideration of heat transfer resulting from both radiation and convection.
For the lower compartment in containment, the licensee assumed two temperature profiles corresponding to flame velocities of 1 fps and 6 fps.
The tempera-ture profiles corresponding to 1-fps flame velocity consisted of three burns with the average time between the burns of 250 sec.
The temperature profile for flame velocity of 6 fps consisted of six burns with the average time between the burns of 220 sec.
In both cases, the CLASIX generated profiles were modified so that the highest temperature reached by the gas was equal to the adiabatic flame temperature of 1400 F.
For the ice condenser upper plenum the licensee assumed an ambient temperature corresponding to a continuous hydrogen burn at the top of the ice condenser lasting for 45 min.
This is a conservative assumption because intermittent rather than continuous burning is the phenomenon likely to occur in the ice condenser region.
The staff has reviewed and concurs with the choice of thermal environments used by the licensee because they conservatively represent the thermal environments to which the given equipment would be exposed during an accident.
The thermal responses for thermocouple cable and for both licensee-and vendor-supplied RTD cables were analytically predicted using the lower compartment thermal environments corresponding to flame velocities of 1 fps and 6 fps.
The Barton transmitter was analyzed assuming a single burn with a flame velocity of 2 fps; however, its thermal respcnse under this condition was so low that when it was extrapolated to the thermal conditions postulated for the lower compart-ment the resulting peak temperature did not exceed the qualification temperature.
Thermal responses for the igniter assembly and power cable were analytically predicted for the licensee's postulated ice condenser upper plenum thermal envi-ronment.
This environment is considered more severe than the lower compartment environment. The analytical models used in predicting thermal responses of equipment considered thermal energy transfer from the flame and from the hot gases by radiation and convection.
Standard heat transfer equations were used to calculate this heat transfer.
Heat transfer inside the equipment was deter-mined by the licensee using the HEATING 5 computer code (0ak Ridge National Labor-atory).
Equipment components were represented in the code by models of rela-tively simple geometry which possessed all the significant heat transfer charac-teristics of the equipment.
The same HEATING 5 code was used by TVA in calcu-lating thermal responses in the Sequoyah plant.
TVA verified the code using experimental data from the tests performed in Fenwal Laboratory (Fenwal,1980).
In addition, the staff's consultant, Sandia, performed independent verification of the thermal response analyses performed by TVA for Sequoyah and concluded that the results a e conservative (McCulloch, 1982).
Because the Sequoyah and McGuire SSER 7 C-18
a McGuire plants are very similar, these conclusions apply to both plants.
The staff has reviewed the methodology used by the licensee and all the verifica-tion evidence and concludes that the thermal responses of equipment calculated by this method have adequate margins of conservatism.
The acceptance criterion used for evaluating survivability of essential equip-ment is based on the qualification temperature of the equipment located in the containment.
The criterion is that essential equipment will survive the hydro-gen burn event if the temperature reached by its most sensitive component does not exceed the temperature reached by this component during qualification tests.
Because the actual temperature reached by the test equipment during these tests was not measured, and qualification temperature was the temperature of the envi-ronment to which the test equipment was exposed, there is no direct way to deter-mine the actual temperature components during the qualification test.
- However, Duke claims that environmental qualification tests are typically conducted for an extended period of time so that the equipment curface temperature would achieve thermal equilibrium with the test chamber during the tests.
Because the heat transfer to the equipment during the qualification testing could be modeled by a simple analytical model and engineering judgment could be made on the long duration of the qualification testing, the staff believes that the measurement of surface temperature is not necessary during qualification testing.
- Also, because of several conservative ascumptions in the thermal response analysis, the staff concludes that use of qualification temperature by Duke as a crite-rion for evaluating the survivability of limiting components is acceptable.
All equipment listed in Table C.2, except for core exit thermocouples and hydro-gen igniters, has been included in the Duke equipment qualification (EQ). pro-gram.
Core exit thermocouples are not qualified yet but will be qualified by the next refueling to comply with TMI Item II.F.2 requirements.
Hydrogen ignit-ers are also not included in the qualification program.
However, the functional capability of the igniters has been demonstrated in tests conducted at Fenwal and Whiteshell in an atmosphere of burning hydrogen.
Moreover, similar igniter assemblies were recently qualified by Grand Gulf in accordance with NUREG-0588 Category I requirements.
Based on these findings the staff concludes that there is adequate assurance that the hydrogen igniters will survive the hydrogen burn event.
Recently, the staff was informed by the Power Systems Division of Morrison Knudsen (Cake, 1983) about a possible reportable defect under 10 CFR 21 concern-ing the General Motors glow plug used in the hydrogen igniter assemblies.
The defect was related to a change in manufacturing process from brazing to hot rolled compression fit and resulted in some failures during pneumatic leak test-ing.
It was determined that the change in manufacturing process for the glow plugs was made by General Motors in June 1982.
All glow plugs manufactured before that time are of brazed construction and are therefore not subject to the deficiency reported to the NRC.
Duke has informed the staff that the hydrogen mitigation system in both McGuire Unit 1 and McGuire Unit 2 contains glow plugs manufactured before June 1982, and is therefore not affected by the reported deficiency.
Duke has also verified that his spare parts stock contains none of the affected units. Accordingly, the 10 CFR 21 report issued by Power Systems is not applicable to McGuire Nuclear Station.
McGuire SSER 7 C-19
Duke has provided the results of survivability analyses for the selected essen-tial equipment.
The analytically calculated thermal responses during hydrogen burn are compared with the qualification temperatures in Table C.3.
With one exception, the vendor-supplied RTD cable, the design / qualification temperature was found to be higher than the calculated responses.
Futhermore, a similar cable has been tested by TVA at their Singleton laboratory in an atmophere of burning hydrogen (Mills, 1981).
In this test, the cable was repeatedly exposed to temperatures of 1400 F and reached a measured temperature of 993 F.
The subsequent high voltage testing indicated that its dielectric strength was not impaired by this exposure. Although CLASIX does not predict any burns in the upper compartment, the licensee has considered the effect of upper compartment burns on equipment survivability and concludes that upper compartment burning will have no significant effect on the operability of either the hydrogen recom-l biners or the air return fans because of the short duration of the hydrogen burn and the low baseline temperature for the compartment.
Table C.3 Comparison of analytically calculated thermal responses during hydrogen burn and qualification temperatures Maximum temperature, F Design / qualification Component (calculated) temperature, F 4
Igniter Interior box air 400 428 (transformer)
Transformer core 400 Barton transmitter Interior 310 (estimated) 320 Igniter power cable 700 1200 Thermocouple cable Outer armor 385 346 Insulation 338 RTD cable (licensee supplied) f Outer armor 382 346 Insulation 322 RTD cable 400 332 i
(vendor supplied) l McGuire SSER 7 C-20 l
i It should be noted that the tests conducted by the industry were performed in a relatively small oven.
In NUREG/CR-2730, the staff's contractor, Sandia, stated that on tha basis of some preliminary test results, scaling (volume of containment building vs. volume of the test chamber) may be a significant fac-tor in analyzing the survivability of the equipment.
However, on the basis of the conservative assumptions and available margins in the work done to date, the staff believes that even after taking the scaling effect into considera-tion, the equipment will be found to survive the hydrogen burn environment.
During fiscal year 1983, Sandia and EPRI will be performing some additional confirmatory tests to address this issue.
The results from these upcoming tests will be relied on to confirm the findings made above.
Secondary fires in the McGuire plant originate either when combustible materi-als located in the containment reach ignition temperatures or when the insula-tion on the ice condenser's cooling ducts is heated to the point at which poly-urethane foam starts to decompose and emit combustible gases.
The licensee, after reviewing different possible sources of combustible materials, identified organic cable insulation and the reactor coolant pump oil as the only signifi-cant sources..In most cases, however, cables are completely enclosed in con-duits or cable trays, and are not directly exposed to the hydrogen burn.
The licensee has also demonstrated that even those cables that have exposed insula-tion will not reach the temperature at which they may ignite.
The same applies to the coolant oil which is contained within massive oil reservoirs with large thermal capacities. These reservoirs will not reach the ignition temperature of oil when exposed to the postulated hydrogen burn environment.
In evaluating the thermal stability of ice condenser cooling duct insulation, the licensee has performed an analysis using the HEATING 5 computer code. On the basis of the results of this analysis, Duke concluded that no degradation of the foam insulation or release of combustible gas will occur.
The staff has reviewed this analysis and concurs with the licensee's conclusion.
C.8.3 Pressure Effects With the HMS, the highest pressure in the containment during a hydrogen burn event does not exceed the pressures to which essential equipment is qualified.
The licensee has performed analyses using the CLASIX code which indicated that the differential pressures developed across the air return fans and hydrogen skimmer fans during a postulated burn in the upper compartment will not chal-lenge the structural integrity of the fans.
Furthermore, the licensee has stated that the predicted pressure differential will not significantly affect performance of these fans.
The staff has reviewed the licensee's analyses and concurs with his statement that the fans will remain operable during and fol-lowing hydrogen burning in containment.
C.8.4 Staff Conclusions Regarding Equipment Survivability After reviewing Duke's analytical investigation of equipment survivability and other industry research on equipment survivability, the staff concludes that Duke has provided sufficient evidence that all the equipment required to ensure safe shutdown conditions and containment integrity will survive the environment created by burning of the hydrogen generated during a postulated accident.
This conclusion is based on the following:
I McGuire SSER '
C-21
l
~
(1) The list of equipment provided in the submittal included all the essential equipment.
(2) The equipment selected for the analytical investigations adequately charac-terizes the essential equipment on the list.
(3) The analytical methods used by the licensee adequately calculate thermal response of equipment on the basis of the postulated thermal environment.
(4) The comparison of analytically determined thermal responses with the corre-sponding qualification and/or design temperatures for some sample compo-nents has indicated that these temperatures will not be exceeded during a hydrogen burn.
(5) It was satisfactorily demonstrated that burning hydrogen will not initiate secondary fires in the containment by igniting combustible materials or by generating combustible gases from the decomposition of polyurethane foam insulation.
C.9 OVERALL CONCLUSIONS The staff has concluded its review of the matter of hydrogen control for postu-lated degraded core accidents at the McGuire Nuclear Station.
In the course of the review, the staff requested Duke to make a number of modifications to the HMS to provide added assurance that the system will operate in the intended manner with adequate safety margins.
Specifically, the staff requested Duke to (1) add or relocate igniters to the lower elevations of tne lower and upper compartments of containment and (2) provide a means of verifying the HMS status from the control room. Duke has committed to make the appropriate modifications to McGuire Units 1 and 2 before restart following the next refueling for each unit. The staff finds this time frame and operation during the interim period acceptable. Subject to the satisfactory resolution of these contingencies, the staff finds that:
(1) The peak pressures as a result of igniter-induced burns will be 1;ss than the containment pressure capacity.
The results of many accident analyses indicate that the peak containment atmosphere pressure will be close to the design pressure of 15 psig. Even considering a broad range of accident scenarios and combustion assumptions that are more ccnservative than the base case, it is expected that the containment pressure will remain below 30 psig. With adequate margins, the ultimate pressure capacity of the containment has been determined to be 48 psig.
(2) The essential equipment has been identified and the peak temperatures during a hydrogen burn for the most sensitive pieces of equipment have been shown to be less than their qualification temperature.
4 As part of its HMS evaluation, the staff also identified a number of technical concerns that it will be continuing to investigate as confirmatory items.
The confirmatory items are:
(1) local detonations (2) containment code work McGuire'SSER 7 C-22
i' (3) equipment survivability for a spectrum of accidents (4) combustion effects at large scale (5) combustion phenomena including flame acceleration and igniter operability in a spray environment The subject of local detonations in confined regions of the containment is cur-rently under investigation at Sandia under a staff technical assistance contract.
This work is considered confirmatory in nature because (1) mixing of the contain-ment atmosphere in conjunction with igniter operation at low hydrogen concentra-tion will preclude the formation of detonable mixtures and (2) recent analyses performed by Sandia using the CSQ code and a refined structural analysis indi-cate that the ice condenser containment can withstand the postulated detonation of a 20 volume percent hydrogen mixture in the upper plenum. The Sandia investigation should be completed by late 1983.
The staff will continue to assess the adequacy of the CLASIX code as part of its technical assistance program with the Los Alamos National Laboratory and its hydrogen research program at Sandia. This containment code work is considered to be confirmatory in light of the staff's findings regarding the adequacy of the CLASIX models and the reasonable agreement obtained between CLASIX, COMPARE, and HECTR. The code work will be an ongoing effort.
The staff will also continue to investigate equipment survivability for a spec-trum of degraded core accidents. This investigation will be carried out as part of the NRC Hydrogen Burn Survival Program already in place at Sandia. The favor-able results of the survivability analyses for the more temperature-sensitive pieces of equipment provide the bases for classifying this item as confirmatory.
The staff will monitor the results of other ongoing NRC and EPRI hydrogen research programs to confirm (1) the margins provided by the HMS, (2) the absence of significant flame acceleration at large scale, and (3) the reliable operation of thermal igniters in a spray environment.
Research programs to address these concerns will be performed at the Nevada test site and at Sandia.
These programs are considered confirmatory because similar test programs have been completed at smaller scale with acceptable results.
Accordingly, subject to meeting the conditions discussed herein dealing with igniter number and locations and system status indication, and subject to com-pleting installation, the staff finds the McGuire Units 1 and 2 license condi-i tions dealing with hydrogen control during postulated degraded core accidents to be satisfactorily resolved.
C.10 REFERENCES American Society of Mechanical Engineers, " Boiler and Pressure Vessel Code,"
Section IV, Division 1.
Berman, M., Sandia, letter to J. T. Larkins, NRC, enclosing April and May 1982 status reports for the Sandia Hydrogen Programs, July 20, 1982.
l l~
McGuire SSER 7 C-23 i
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Cake, M. P., Powers Systems Division of Morris Knudsen, letter to NRC Region II Office (Attn. J. D. O'Reilly), " Hydrogen Igniters (Possible Reportable Defect - 10 CFR 21), January 28, 1983.
Duke Power Company, An Analysis of Hydrogen Control Measures at McGuire Nuclear Station, February 17, 1981.
Eisenhut, D., NRC, letter to all licensees of operating reactors, applicants for operating licenses, and holders of construction permits, " Supplement 1 to NUREG-0737 Requirements for Emergency Response Capability" (Generic Letter No. 82-33), December 17, 1982.
Fenwal Laboratory, "Sequoyah Nuclear Plant Core Degradation Program, Volume 2, Report on Safety Evaluation of the Interim Distributed Ignition System,"
December 15, 1980.
McCulloch, W. H., Sandia, letter to K. Parczewski, NRC, October 29, 1982.
Mills, L. M., TVA, letter to E. Adensam, NRC, June 2, 1981, Attachment A.
Oak Ridge National Laboratory (0RNL), " HEATING 5, an IBM 360 Heat Conduction Program," ORNL/CSD/TM-15.
Parker, W.
0., Duke, letter to H. R. Denton, NRC, "An Analysis of Hydrogen Control Measures at McGuire Nuclear Station," October 30, 1981; Revision 1, December 31, 1981, Revision 2, January 22, 1982; Revision 3, March 11, 1982; Revision 4, May 4, 1982; Revision 5, November 5, 1982; Revision 6, February 15, 1983; Revision 7, March 16, 1983; Revision 8, April 22, 1983.
U.S. Nuclear Regulatory Commission, "NRC Staff Analysis of Hydrogen Control Measures for McGuire Nuclear Station, Units 1 and 2," Docket Nos. 50-369 and 50-370, February 17, 1981.
--, NUREG-0011, " Safety Evaluation Report Related to the Operation of Sequoyah Nuclear Plant, Units 1 and 2," Docket Nos. 50-327 and 50-328, January 1976; Supplement 3, September 1980; Supplement 4, January 1981; Supplement 5, June 1981; Supplement 6, December 1982.
--, NUREG-0588, " Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment," December 1979.
--, NUREG/CR-1891, " Reliability Analysis of Containment Strength--Sequoyah and McGuire Ice Condenser Containment," Ames Laboratories, August 1982.
--,NUREG/Cht-2730;"HydrogenBurnSurvivalThermalModelandTestResults,"
Sandia, August 1982.
--, NUREG/CR-3278, " Hydrogen Burn' Analyses of Ice Condenser Containments,"
Los Alamos National Laboratory, April 1983.
Westinghouse Electric Corporation, " Zion Probabilistic Safety Study," Module 4,
.Section 4, NRC Docket Nos. 50-295 and 50-304, 1981.
McGuire SSER 7 C-24
--, WCAP-8077, " Ice Condenser Containment Pressure Transient Analysis Methods" (Proprietary Class 2), March 1973; WCAP-8078 (Proprietary Class 3), March 1973.
-Westinghouse Offshore Power Systems, OPS-36A31; "The CLASIX Computer Program for the Analysis of Reactor Plant Containment Response to Hydrogen Release and Deflagration" (nonproprietary; OPS-0735, proprietary).
Yang, J. W., and W. T. Pratt, "A Study of Hydrogen Combustion During Degraded Core Accidents in PWR in Condenser Plant," Brookhaven National Laboratory,
' Department of Nuclear Energy, prepared for NRC under Interagency Agreement DE-AC02-76CH00016, January 1982.
McGuire SSER 7 C-25
___.______m_-
- - - - - - - - - - - - - _ ___m__
4 APPENDIX 0 MCGUIRE hUCLEAR STATION SAFETY EVALUATION REPORT CONCERNING THE REACTOR TRIP BREAKERS McGuire SSER 7
1 I
l TABLE OF CONTENTS Page D.1 INTRODUCTION..................................................
D-1 D.1.1 Description of the Reactor Protection System and Trip Breakers..........................................
D-1 0.1. 2 Reactor Trip Breaker Failure Experience................
D-4 0.2 IDENTIFICATION OF CAUSE OF BREAKER FAILURE TO TRIP............
0-10 0.2.1 Description of Investigation by Licensee...............
0-10 D. 2.1.1 McGuire Unit 1................................
0-10 D.2.1.2 McGuire Unit 2................................ D-10 D.2.2 Conclusions by Licensee Regarding Cause of Failure.....
D-11
- 0. 2. 2.1 McGuire Unit 1................................
D-11 0.2.2.2 McGuire Unit 2................................
D-11 0.2.3 Conclusions by Franklin Research Center Regarding Cause of Failure.......................................
D-12 D.2.4 Conclusions by Staff Regarding Cause of Failure........
D-12 D.3 MAINTENANCE AND TESTING PROCEDURES............................
D-13 0.3.1 Proposed Revisions to Maintenance and Testing Procedures.............................................
D-13 0.3.2 Conclusions by Staff Regarding Maintenance.............
D-14 D.4 PERIODIC SURVEILLANCE TESTING 0F REACTOR TRIP BREAKERS........
D-14 D.4.1 Surveillance Procedures................................
D-14 0.4.2 Conclusions by the Staff Regarding Surveillance........
D-15
'D.5 REACTOR TRIP BREAKER MODIFICATION.............................
D-16 D.5.1 Description of the Modification........................
D-16
.D.5.2 NRC Preliminary Evaluation.............................
0-17 D.5.3 NRC Final Evaluation...................................
D-18 0.5.4 Conclusions on Reactor Trip Breaker Modification.......
D-20 D.6 LICENSEE'S RESPONSES TO WESTINGHOUSE NOTIFICATION.............
0-20 0.6.1 Westinghouse March 31, 1983 Letter.....................
D-20 0.6.2 Westinghouse 10 CFR 21 Notification....................
D-21 0.6.3 Conclusion.............................................
0-21 McGuire SSER 7 D-iii
i TABLE OF CONTENTS (Continued)
Page 0.7 HUMAN FACTORS CONSIDERATIONS RELATED TO DESIGN MODIFICATIONS.. -D-21 D.7.1 Revised ATWS Operating Procedures......................
D-21 D.7.2 Post-Trip Procedures...................................
D-22 D.7.3 Operator Training.....................................
D-25 D.8
SUMMARY
AND CONCLUSIONS.......................................
D-25 D.9 REFERENCES....................................................
D-26 FIGURE D.1 R e a cto r Tr i p Sy s tem............................................
D-3 D.2 Basic Breaker Mechanism........................................
D-5 0.3 Operation of the Breaker.......................................
D-6 D.4 Shunt Trip Attachment..........................................
D-7 D.5 Under Voltage Trip Device Operation............................
D-8 ATTACHMENT 1........................................................
D-28 McGuire SSER 7 D-iv
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4 D.1 INTRODUCTION As a result of failures of the reactor protection system (RPS) breakers at several facilities, the U.S. Nuclear Regulatory Commission is3ued Office of Inspection and Enforcement Bulletins (IEBs) 83-01 and 83-04 and Information
~ Notice 83-18.
Duke Power Company (the licensee), in response to IEB 83-04, performed tests on the Westinghouse 05-416 breakers used at the McGuire facility.
No failures occurred in these tests.
However, subsequent testing resulted in failures of the DS-416 breakers.
These failures were attributed to a variety of causes indicating weaknesses in design and manufacture.
These findings have indicated a need for regulatory action relative to McGuire
-in the form of a comprehensive set of requirements to improve the reliability of the RPS breakers.
Some of the actions identified would require 3 to 9 months to complete.
Until these actions are completed, compensatory actions were deemed necessary.
In addition to the actions proposed by the licensee, the following set of actions was determined to be necessary:
(1) The-licensee must commit to conduct a life-test of a statistically significant sample of the undervoltage (UV) trip device /DS-416 breakers on a prompt basis. Within 45 days, the licensee should provide the program plans for the testing and the schedule for its completion.
(2) The licensee must commit to conduct the special periodic.RPS breaker surveillancr tests identified by the staff.
This safety evaluation report describes the reactor protection system trip breakers.and discusses the background of failures of the DS-416 breakers, reviews the licensee's maintenance and testing procedures, and identifies causes of the breaker failures. On the basis of this evaluation, proposed modifications to installation, quality assurance, maintenance, and surveillance of the DS-416 breakers are identified. The licensee's proposals for actions responding to the 05-416 breaker failures are reviewed against the staff posi-tions and the conclusions are presented regarding the operation of McGuire Units 1 and 2.
D.1.1' Description of the Reactor Protection System and Trip Breakers The reactor protection system (RPS) at this station is designed by the Westing-house Company to sense several plant variables and to actuate a trip of the reactor (emergency shutdown) in the event that any plant variable reaches an abnormal value (setpoint). The RPS consists of multiple instrument channels -
and logic units to cause the holding power to the control rods to be. interrupted.
When this power is interrupted by the circuit breakers, the control rods fall into the reactor. core and thereby terminate the nuclear reaction process.
The overall functions of the RPS are to ensure that fuel design' limits are not i
exceeded during a plant transient (anticipated operational occurrence) and to sense the onset of accidents-and function in conjunction with the engineered i
safety feature systems to limit the consequences of. accidents to acceptable McGuire SSER 7 U-1 4
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The RPS is designed to comply with applicable NRC regulations, includ-ing the General Design Criteria (GDC) in Appendix A to 10 CFR 50.
Because the RPS is a safety-related system, it must be designed, constructed, installed, operated, maintained, and tested in accordance with the quality assurance criteria in Appendix B to 10 CFR 50.
Of the GOC, the most germane to the issue is GDC 23, which requires that, for conditions such as loss of electric power, the RPS must fail to a safe state.
Traditionally, this criterion has been applied as requiring the RPS design to
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be such that it intrinsically causes an automatic reactor trip upon loss of l
power to the RPS.
Therefore, RPS designs include undervoltage (UV) trip mechanisms as part of the reactor trip breakers.
The UV trip is energized dur-ing normal plant operation and will trip the breaker either when power is lost or when power to the UV trip is interrupted by automatic or manual protective signals.
The present design of the RPS at this plant is summarized below and is shown in Figure D.1.
The system consists of multiple instrumentation channels (sensors, transmitters, bistables, and field contacts) that monitor various plant vari-ables. Typically, there are four redundant instrument channels per variable; this varies somewhat depending on the particular parameter.
The outputs of these instrument channels are used as inputs to each of two redundant trains of coincident logic circuitry (solid-state protection system (SSPS) trains "A" and "B").
The output of each SSPS train provides power for two undervoltage trip attachments, one for its associated reactor trip breaker and one for the bypass breaker that may be connected in parallel with the alternate (redundant) reactor trip breaker. When two of the four instrument channels for a given variable are in the tripped state (i.e., the value has exceeded its setpoint), the logic of each SSPS train is satisfied and power is interrupted to the undervoltage trip attachment. This loss of power automatically opens the circuit breakers.
When either of tha two series reactor trip breakers opens, power provided from the motor generator sets to the control rod drive mechanisms is interrupted, thus allowing all control rods to drop into the core.
Manual reactor scram capability is provided by two switches on the main control board in the control room.
At the McGuire station, the manual scram switches are " channelized"; that is, the Train "A" manual scram switch operates the UV and the shunt trip of the reactor trip breaker "A"; the Train "B" switch, reactor trip breaker "B".
Either switch operates both the bypass breakers.
Thus, diverse means (undervoltage trip attachments and shunt trip attachments) are used to open the reactor trip breakers on a manual reactor trip signal, whereas_only the undervoltage trip attachments are actuated on an autcmatic reactor trip signal from the SSPS.
As shown also in Figure 0.1, the design includes a bypass' breaker around each reactor trip breaker. The bypasses are provided to test the main trip breaker without tripping the plant.
Typically during plant operations, the bypass breakers are not closed.
The bypass breakers can be in operation only on a one-at-a-time basis and then only for a limited time as necessary for testing.
The reactor trip breakers are Westinghouse Model 05-416 1600 amp 480 V power circuit breakers.
These breakers operate on the magnetic de-ion principle of interruption.
In these breakers the arc rises from the main contacts into a series of insulated plates.
These plates break the arc into a series of smaller McGuire SSER 7 D-2 4
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INSTRUMENT CHANNELS ACTUATION LOGICS SENSORS BISTABLE TRIPS u,
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i arcs to cool and extinguish them and funnel the heat to ambient air.
The breakers are designed for use in metal enclosed switchgear and are equipped with spring-stored energy closing mechanisms.
The basic breaker mechanism is depicted in Figure 0.2.
These breakers are supplied with a shunt trip attachment (energize to actuate) and an undervoltage trip attachment (deenergize to actuate) for purposes of opening the breaker remotely.
See Figures 0.3, D.4, and D.S.
There is also a mechanical trip mechanism for opening the breaker locally.
D.1.2 Reactor Trip Breaker Failure Experience This section discusses the failure experience of the reactor trip breakers (RTBs) at the McGuire facility. The followup investigative testing conducted by the licensee as a result of these failures is discussed in Section 0.2 of this report.
The summary below reflects the staff's current understanding of the failures and was compiled from discussions with the licensee, numerous letters provided by the licensee, and information from the staff's regional office.
Shortly after the Salem anticipated transients without scram (ATWS) events, the McGuire licensee provided a letter dated February 28, 1983 stating that no RTB failures had occurred. A March 1, 1983 letter corrected the previous letter by stating that one RTB failure in Unit 2 had occurred during preoperational testing.
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Further clarification was provided by letters dated March 22, April 18, April 28, May 3 and May 5, 1983 The staff considers a failure to be either a lack of functional capability demonstrated during testing or a nonconformance with a critical characteristic such as a physical dimension.
Further, if a device failed a test and subse-quent attempts to actuate the device were also unsuccessful, each is considered a failure for the purposes of this report. All the failures were found during testing while the McGuire units were shut down.
(1) On February 4,1983, Unit 2 RTB "B" faihd five consecutive times during routine RPS functional testing.
After the breaker was operated by the
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shunt trip, all subsequent UV trip tests that day were successful.
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work request was initiated, which was executed on February 18, 1983.)
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(2) On February 16,1983, Unit 2 RTB "B" failed several times during routine RPS response-time testing.
(3) On March 16, 1983, all Unit 2 RTBs were tested successfully in response to IE Bulletin 83-04.
(4) On March 17, 1983, all Unit 1 RTBs were tested successfully in response to IE Bulletin 83-04.
(5) On March 18, 1983, Unit 2 RTB "B" failed 3 out of 10 attempts during retesting in the switchgear cubicle, which was initiated because of the February 1983 experience with this breaker. The breaker was moved to a maintenance area for additional testing.
In over 100 tests, 1 or 2 additional failures occurred.
During this testing, after each test of McGuire SSER 7 0-4
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