ML20206H469
| ML20206H469 | |
| Person / Time | |
|---|---|
| Issue date: | 04/30/1999 |
| From: | Emrit R NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES) |
| To: | |
| References | |
| NUREG-0933, NUREG-0933-S23, NUREG-933, NUREG-933-S23, NUDOCS 9905110218 | |
| Download: ML20206H469 (450) | |
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( % , * * * * * ,cr Page 1 of 2 APRIL 1999 SUPPLCMENT 23 TO NUREG-0933 "A PRIORITIZATION OF GENERIC SAFETY ISSUES" REVISION INSERTION INSTRUCTIONS Remove Insert
Introduction:
pp. 29 to 62, Rev. 22 pp. 29 to 88, Rev. 23 Sechon 1: pp.1.1.F-1 to 7, Rev. 3 pp.1.1.F-1 to 7, Rev. 4 pp.1.ll.D-1 to 4, Rev. 2 pp.1.ll.D-1 to 4, Rev. 3 pp.1.ll.E.2-1 to 7, Rev. 2 pp.1.II.E.2-1 to 7, Rev. 3 pp.1.ll.E.5-1 to 4, Rev.1 pp.1.ll.E.5-1 to 4, Rev. 2 pp.1.ll.E.6-1 to 4, Rev.1 pp.1.ll.E.6-1 to 4, Rev. 2 pp.1.II.F-1 to 7, Rev. 2 pp.1.ll.F-1 to 7, Rev. 3 pp.1.ll.G-1 pp.1.ll.G-i, Rev.1 pp.1.ll.H-1 to 5, Rev. 2 pp.1.II.H-1 to 5, Rev. 3 pp.1.ll.J.1-1 to 3 pp.1.II.J.1-1 to 3, Rev.1
[s pp.1.ll.J.2-1 to 3 pp.1.ll.J.2-1 to 3, Rev.1 ,
pp.1.II.J.3-1 pp.1.ll.J.3-1, Rev.1 pp.1.II.J.4-1 to 2 pp.1.ll.J.4-1, Rev. 3 pp.1.lli.D.2-1 to 13, Rev. 2 pp.1.Ill.D.2-1 to 13, Rev. 3 Section 2: pp. 2.A.21-1 to 3 pp. 2.A.21-1 to 3, Rev.1 pp. 2.A.38-1 to 4, Rev.1 pp. 2.A.38-1 to 4, Rev. 2 pp. 2.D.1-1 to 4 pp. 2.D.1-1 to 5, Rev.1 Section 3: pp. 3.35-1 to 9, Rev.1 pp. 3.35-1 to 9, Rev. 2 pp. 3.71-1 to 8, Rev.1 pp. 3.71-1 to 8, Rev. 2 pp. 3.80-1 to 8, Rev.1 pp. 3.80-1 to 8, Rev. 2 pp. 3.90-1 to 11, Rev.1 pp. 3.90-1 to 11, Rev. 2 pp. 3.92-1 to 5 pp. 3.92-1 to 5, Rev.1 f pp. 3.107-1 to 6, Rev.1 pp. 3.107-1 to 6, Rev. 2 J pp. 3.122-1 to 23, Rev. 3 pp. 3.122-1 to 24, Rev. 4 pp. 3.125-1 to 79, Rev. 6 pp. 3.125-1 to 77, Rev. 7 pp. 3.138-1 to 6, Rev.1 pp. 3.138-1 to 6, Rev. 2 pp. 3.144-1 to 6, Rev.1 pp. 3.144-1 to 6, Rev. 2 pp. 3.145-1 to 6, Rev.1 pp. 3.145-1 to 6, Rev. 2 pp. 3.149-1 to 4, Rev.1 pp. 3.149-1 to 4, Rev. 2 pp. 3.152-1 to 4, Rev.1 pp. 3.152-1 to 4, Rev. 2 pp. 3.154-1 to 5, Rev.1 pp. 3.154-1 to 5, Rev. 2 pp. 3.156-1 to 32, Rev. 4 pp. 3.156-1 to 31, Rev. 5 O' pp. 3.168-1, Rev.1 pp. 3.168-1 to 2, Rev. 2 l
9905110218 990430 ,
Page 2 of 2 Remove Insert
- pp. 3.169-1 to 5 pp. 3.170-1 to 4 pp. 3.170-1 to 3, Rev.1 pp. 3.171-1 to 9 pp. 3.171-1 to 9 Rev.1 pp. 3.172-1 to 18 pp. 3.172-1 to 17, Rev.1 pp. 3.173-1 to 4, Rev.1 pp. 3.173-1 to 5 Rev. 2 pp. 3.190-1 pp. 3.190-1, Rev.1 pp. 3.191-1 pp. 3.191-1, Rev.1
References:
pp. R-1 to R-113, Rev.12 pp. R-1 to R-120, Rev.13 Appendix B: pp. A.B-1 to 12, Rev.13 pp. A.B-1 to 13, Rev.14 Appendix F: pp. A.F-1 to 2 pp. A.F.0-1 to 4, Rev.1 pp. A.F.1-1 pp. A.F.2-1 pp. A.F.3-1 pp. A.F.4-1
- pp. A.F.5-1 pp. A.F-6-1 pp. A.F.7-1 pp. A.F.8-1 pp. A.F.9-1 pp. A.F.10-1 pp. A.F.11-1 pp. A.F.12-1 ,
pp. A.F.13-1 .
pp. A.F.14-1 .
pp. A.F.15-1
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-TASK l.F: QUALITY ASSURANCE The objective of this task was to improve the quality assurance program (QA) for design, construction, and operations to provide greater assurance that plant design, construction, and operational activities were conducted in a manner commensurate with their importance to safety.
ITEM l.F.1: EXPAND QA LIST DESCRIPTION Historical Backaround The TMI Action Plan" identified that several systems important to the safety of TMI-2 were not I designed, fabricated, and maintained at a level equivalent to their safety importance, i.e., they were not on the QA List for the plant. This condition existed at other plants and resulted primarily from the lack of clarity in NRC guidance on graded protection. Evaluation of this issue included the consideration of Issue 5 (see Section 3).
Safety Sionificance
- 9. One of the difficulties in establishing a QA list based on safety importance was the absence of relative risk assignments to equipment. At the time this issue was initially evaluated, QA requirements were applied principally to structures, systems, and components that prevented or <
mitigated the consequences of postulated accidents that could cause undue risk to the health and safety of the public (10 CFR 50, Appendix B).
Possible Solution The TMI Action Plan stated that the NRC would develop guidance for licensees to expand their j QA lists to cover equipment important to safety and rank the equipment in order of its importance l to safety. Experience in the use of the revised NRR review procedure for developing QA lists for ;
individual operating license applicants were to be factored into the generic guidance to be ;
developed and when determining backfit requirements." At the time this issue was identified, there was a task underway to define the applicability of 10 CFR 50, Appendix B, to equipment that met 10 CFR 50, Appendix A.
PRIORITY DETERMINATION The principal benefit to be derived from an expanded QA list was the knowledge adequate guidance provided each licensee to establish QA programs and requirements that were commensurate with the safety importance of structures, systems, and components, as determined from completed risk assessments. This guidance would not only result in the inclusion or addition of other systems important to safety to each licensee's QA list that were previously excluded, but would also aid in clarifying the QA level of effort deemed necessary.
12/31/98 1.1.F-1 NUREG-0933
Revision 4 '
The risk reduction was probably proportionate to the difference between what would normally be the level of effort expended and the level defined. At the time this issue was initially evaluated, there was no measure of risk variation as a function of the variance in QA level of effort. However, it appeared reasonable to assume that a significant reduction in public risk could be achieved at those plants where the QA levels were held to the previous minimum acceptable level. Important I questions to which there were no answers were: (1)ine number of plants that would be designed, I built, and maintained below the new quality acceptance level; and (2) how far below the new level the QA programs of these plants would actually operate.
Cost Estimate Industry Cost: It was estimated that (1) the plant user cost applied to 40 plants in the design phase or under construction; (2) an average of 0.5 man-year / plant was required to develop an expanded QA list; (3) an additional 0.25 man-year / plant over 4 years was required to ensure compliance with the added QA requirements; and (4) an additional 0.1 man-year / plant would be expended to ensure compliance with the expanded QA list during the 40-year operating life of each affected plant. These estimates totaled 220 man-years and, at a rate of $100,000/ man-year, the total industry cost was estimated to be $22M.
NRC Cost: The NRC cost was estimated in the TMI Action Plan" to be 2.5 man-years or $0.25M. l Total Cost: The total industry and NRC cost associated with the solution was $(22 + 0.25)M or
$22.25M.
CONCLUSION Although a value/ impact score was not calculated, the staff believed that the assurance of safer operation justified a high priority ranking for the issue. l The original intent of this issue war to identify those systems, structures, and components beyond those labeled " safety-related," prioritize their importance to safety, and prepare a generic QA list.
This was reflected in 10 CFR 50.34 (f)(3)(ii) which states: " ensure that the Quality Assurance (QA)
List required by Criteria 11 App. B,10 CFR Part 50 includes all structures, systems and components important to safety (l.F.1)." However, the staff's IREP Procedures Guidest2 failed to identify either the need for a OA list for structures, systems, and components important to safety (ITS) or the basis for a generic list even if one should be needed. The first four IREP studies performed at 3
nuclear plants were reported in NUREG/CR-2787 88 NUREG/CR-2802,387 NUREG/CR-3085,85 and NUREG/CR-3511.8" The staff's resolution of the IREP issue is discussed in item II.C.1.
In January 1984, Generic Letter 84-01"77was issued to clarify NRC use of the terms,"important to Safety" and " Safety Related." This letter summarized NRC's intention to pursue QA requirements for important to safety equipment on a case-by-case basis; further clarification was provided in the Commission's Memorandum and Order CLI-84-9"78 in June 1984. The first proposed rule on ITS was presented in SECY-85-119"78 and was later disapproved by the Commission who concluded that a specific listing of ITS equipment was not required to be maintained."8 Thus, the issue of expansion of the QA list to coverITS equipmentwas considered closed and was not addressed in the second staff submittal on the ITS rule in SECY-86-164."8' Therefore, this issue was RESOLVED with no new requirements.us2 9
12/31/98 1.1.F-2 NUREG-0933
I Rsvision 4
- ITEM l.F.2
- DEVELOP MORE DETAILED QA CRITERIA l
DESCRIPTION l Historical Backaround l
l The overall objective of this TMI Action Plan" item was the improvement of the QA program for design, construction, and operabons to provide greater assurance that plant design, construction, and operational activities were conducted in a manner commensurate with their importance to safety. Several systems impostant to the safety of TMI-2 were not designed, fabricated, and maintained at a level equivalent to their safety importance. This condition existed at other plants 1 and resulted primarily from the lack of clarity in NRC guidance for graded protection. This situation 2 and other QA problems relating to the QA organization, authonty, reporting, and inspection were l identified by the various TMI acadent investigations and inquiries."
Safety Sianificance The intent of this item was to provide more explicit and detailed criteria conceming the elements that, in general, were found in well-conductM QA programs. Providing these more detailed criteria was expected to result in the establishme ,c of QA programs of the caliber desired. It was believed l that such programs would result in the detection of deficiencies in design, construction, and operation.
l Possible Solutions More detailed QA criteria for design, construction, and operations were proposed considering the following;"
! (1) Ast,ure the independence of the organization performing the checking functions from the l c.ganization responsible for performing the tasks. For the construction phase, consider ogions for inc. easing the independence of the QA function. Include an option to require i
that lice nas perform the eritim a,oality assurance / quality control (QA/QC) function at 1 c%struction sites. Consider using the third-party concept for accomplishing the NRC 1 l review and audit and making the QA/QC personnel agents of the NRC. Consider using INPO to enhance QA/QC independence.
l (2) include the QA personnel in the review and approval of plant operational maintenance and i surveillance procedures and quality-related procedures associated with design, construction, and installation.
(3) Include the QA personnel in all activities involved in design, construction, installation, j preoperational and startup testing, and opersition.
.(4) Establish criteria for determining QA requirements for specific classes of equipment such as instrumentation, mechanical equipment, and electrical equipment.
(5) Establish qualification requirements for QA and QC personnel.
.(6) Increase the size of the licensees' QA staff.
12/31/98 1.l.F-3 NUREG-0933 1- _
i Rsvision 4 (7) Clarify that the QA program is a condition of the construction permit and operating license and that substantive changes to an approved program must be submitted to NRC for review. .
j (8) Compare NRC QA requirements with those of other agencies (i.e., NASA, FAA, DOD) to j improve NRC requirements.
(9) Clarify organizational reporting levels for the QA organization.
(10) Clarify requirements for maintenance of 'as built' documentation. l (11; Define the role of QA in design and analysis activities. Obtain views on prevention of design errors from licensees, architect-engineers, and vendors.
PRIORITY DETERMINATION lt was assumed that the above criteria would be adopted by the nuclear industry. A priority determination was made of the benefit of the above eleven items in improving QA and not of a QA program.
l To address this issue adequately, improvement in the QA program must be developed ;
independent of the performing organization. Furthermore, che QA organization must have the l confidence and the ear of higher management so that QA concerns could be heard and acted l upon. The deficiency of the effort called for in this issue was that the effectiveness of the j improvement program was dependent upon the acceptance, attitudes, and emphasis given by !
plant management to the benefits to be derived from a QA program. Licensees that placed a high ,
importance on QA efforts would probably be able to incorporate the intent of the QA enhancement program without making major changes to their organizational structure or in the way they perform their plant operations. However, for those licensees that continued to do business "as usual," the changes could be more cosmetic than real. They would probably seek ways to establish a QA organization which, on the surface, might appear reasonable but which, in reality, could be a
" paper t:ger." Enclosure 1 of SECY-82-352 8 states:"In sum, the fundamental issues can best be characterized as a lack of total management commitment to quality and the uncertainty in industry's and NRC's ability to detect and correct the resulting deficiencies."
. CONCLUSION While the QA improvement program could result in the establishment of an improved QA organizational structure at many plants, the results depended heavily upon management acceptance. Lack of program implementation and management acceptance, rather than inadequate criteria as suggested by this issue, were the primary causes of deficiencies in QA.
Increasing the detail of the QA criteria had little potential for improving the quality of design, construction, or operation and, therefore, risk. Items 1.F.2(2), l.F.2(3), l.F.2(6), and I.F.2(9), which addressed the concern stated above, were included in the July 1981 revision to Chapter 17 of the SRP."
It was believed that the issue of QA in nuclear power plants should be a high priority. However, the issue and solutions to QA deficiency as described herein (except for the completed issues 1.F.2(2), l.F.2(3), l.F.2(6) and I.F.2(9)] failed to address the problem of management acceptance of QA programs. Hence, the residualitems were given a low priority.
12/31/98 1.1.F-4 NUREG-0933
Rcvision 4 ITEM l.F.2(1): ASSURE THE INDEPENDENCE OF THE ORGANIZATION PERFORMING THE CHECKING FUNCTION This item was evaluated in itsm 1.F.2 above and was determined to be a LOW priority issue.
Consideration of new information'"5 on the lack of independence in the checking function, submitted by Region IV in April 1997, did not change this conclusion.'7'8 '
ITEM l.F.2(2): INCLUDE QA PERSONNEL IN REVIEW AND APPROVAL OF PLANT PROCEDURES This item was evaluated in item 1.F.2 above and was determined to be RESOLVED. New requirements were established with changes to the SRP."
ITEM l.F.2(3): INCLUDE QA PERSONNEL IN ALL DESIGN. CONSTRUCTION. INSTALLATION.
TESTING. AND OPERATION ACTIVITIES This item was evaluated in item 1.F.2 above and was determined to be RESOLVED. New requirements were established with changes to the SRP."
ITEMl F.2(4): ESTABLISH CRITERIA FOR DETERMINING QA REQUIREMENTS FOR SPECIFIC CLASSES OF EQUIPMENT
. This item was evaluated in item 1.F.2 above and was determined to be a LOW priority issue. ,
i ITEM l.F.2(5): ESTABLISH QUALIFICATION REQUIREMENTS FOR QA AND QC PERSONNEL .
l This item was evaluated in item 1.F.2 above and was determined to be a LOW priority issue.
ITEM l.F.2(6): INCREASE THE SIZE OF LICENSEES' QA STAFF This item was evaluated in item 1.F.2 above and was determined to be RESOLVED. New requirements were established with changos to the SRP."
ITEM l.F.2(7): CLARIFY THAT THE QA PROGRAM IS A CONDITION OF THE CONSTRUCTION PERMIT AND OPERATING LICENSE This item was evaluated in item 1.F.2 above and was determined to be a LOW priority issue.
ITEM l.F.2(8): COMPARE NRC QA REQUIREMENTS WITH THOSE OF OTHER AGENCIES
, This item was evaluated in item 1.F.2 above and was determined to be a LOW priority issue.
12/31/98 1.1.F-5 ' NUREG-0933
r Revision 4 ITEM l.F.2(9): CLARIFY ORGANIZATIONAL REPORTING LEVELS FOR THE QA i l ORGANIZATION i This item was evaluated in item 1.F.2 above and was determined to be RESOLVED. New requirements were established with changes to the SRP."
ITEM l.F.2(10): CLARIFY REQUIREMENTS FOR MAINTENANCE OF "AS-BUILT" DOCUMENTATION This item was evaluated in item 1.F.2 above and was determined to be a LOW priority issue.
ITEM l.F.2(11): DEFINE ROLE OF QA IN DESIGN AND ANALYSIS ACTIVITIES This item was evaluated in item 1.F.2 above and was determined to be a LOW priority issue.
REFERENCES
- 11. NUPEG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," U.S. Nuclear Regulatory Commission, (1st Edition) November 1975, (2nd Edition) March 1980, (3rd Edition) July 1981.
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S. '
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
- 64. NUREG/CR-2800, " Guidelines for Nuclear Power Plant Safety issue Prioritization information Development," U.S. Nuclear Regulatory Commission, February 1983, (Supplement 1) May 1983, (Supplement 2) December 1983, (Supplement 3) September 1985, (Supplement 4) July 1986, (Supplement 5) July 1996.
308. SECY-82-352, " Assurance of Quality," August 20,1982. j 1
366. NUREG/CR-2787, " Interim Reliability Evaluation Program: Analysis of the Arkansas l Nuclear One - Unit One Nuclear Power Plant," U.S. Nuclear Regulatory Commission, June l 1982.
367. NUREG/CR-2802," Interim Reliability Evaluation Program: Analysis of the Browns Ferry l Unit 1 Nuclear Plant," U.S. Nuclear Regulatory Commission, August 1982, (Appendices A,B,C) August 1982.
810. NUREG/CR-3085," Interim Reliability Evaluation Program: Analysis of the Millstone Point I
! Unit i Nuclear Power Plant," U.S. Nuclear Regulatory Commission, (Vol.1) April 1983, (Vol. 2) August 1983, (Vol. 3) July 1983, (Vol. 4) July 1983.
l 811. NUREG/CR-3511. " Interim Reliability Evaluation Program: Analysis of the Calvert Cliffs l Unit 1 Nuclear Power Plant," U.S. Nuclear Regulatory Commission, (Vol.1) May 1984, !
(Vol. 2) October 1984, i
12/31/98 1.1.F-6 NUREG-0933 l l
Rsvision 4 ,
l l
812. NUREG/CR-2728, "intenm Reliability Evaluation Program Procedures Guide," U.S. Nuclear I Regulatory Commission, March 1983.
1177. NRC Letter to All Holders of Operating Licenses, Applicants for Operating Licenses and Holders of Construction Permits for Power Reactors, "NRC Use of the Terms, 'important to Safety' and ' Safety Related' (Generic Letter 84-01)," January 5,1984.
1178. NRC Memorandum and Order CLl-84-9, June 6,1984.
1179. SECY-85-119, " Issuance of Proposed Rule on the important-to-Safety issue," April 5, 1985.
1180. MemorandumforW.DircksfromS.Chilk," Staff Requirements-SECY-85-119 ' Issuance of Proposed Rule on the important-to-Safety Issue,'" December 31,1985.
1181. SECY-86-164, " Proposed Rule on the important-to-Safety issue," May 29,1986.
l l
1182. Memorandum for V. Stello from E. Beckjord, " Resolution of Generic issue 1.F.1, ' Expand QA List,'" January 12,1989.
1715. Memorandum to D. Morrison from T. Gwynn, " Periodic Review of Low-Priority Generic j Safety issues," April 16,1997.
I 1716. Memorandum to T. Gwynn from T. Martin," Periodic Review of Low-Priority Generic Safety issues," July 13,1998.
j 12/31/98 1.l.F-7 NUREG-0933 l
Revision 3 TASK ll.D: REACTOR COOLANT SYSTEM RELIEF AND SAFETY VALVES The objective of this task was to demonstrate by testing and analysis that the relief and safety valves, block valves, and associated piping in the reactor coolant syst'.sm (RCS) were qualified for !
the full range of operating and accident conditions; anticipated transients without scram (ATWS) could be considered in later phases of the testing. In addition, design changes or modifications that were necessary to provide positive indication of valve position were to be made.
JTEM ll.D.1: TESTING REQUIREMENTS DESCRIPTION l This TMl Action Plan" item called for applicants and licensees to conduct testing to qualify reactor coolant relief valves, safety valves, block valves, and associated discharge piping for all operating conditions and design basis accidents. j CONCLUSION This item was RESOLVED, requirements were issued, and MPA F-14 was established by DL/NRR i for implementation purposes.
ITEM ll.D.2: RESEARCH ON RELIEF AND SAFETY VALVE TEST REQUIREMENTS Historical Backaround This TMI Action Plan" item speafied that RES contract with INEL to: (1) act as a systems integrator to technically monitor and analyze the planned industry valve test and analytical program at EPRI and collect, analyze, and compare information from foreign tests; (2) develop, improve, or verify available flow discharge and structural response models using the above information; (3) determine the need for a valve testing program by NRC, with the main focus to be on subcooled and two-phase discharge and on determining operability; and (4) conduct additional tests, as necessary, to ensure that the response to the full spectrum of fluid conditions thatwould be expected to result from anticipated operational occurrences and ATWS events had been adequately characterized. The above work, with the exception of the ATWS events, had been performed in conjunction with item II.D.1 which was clarified in NUREG-0737."
Safety Sionificance The remaining concem under item II.D.2 with respect to ATWS events was the capability to depressurize the reactor. Coupled with failure of the reactor protection system (RPS) following a transient, inadequate depressurization could result in rupture of the reactor coolant pressure boundary (RCPB) producing a loss-of-coolant accident (LOCA).
12/31/98 1.II.D-1 NUREG-0933
Revision 3 Possible Solution To estimate the public risk associated with ATWS events, it was assumed" that a possible solution would be to increase the sizing of the relief and safety valves. This modification was assumed to decrease the likelihood of an ATWS-induced rupture of the RCPB by enhancing the depressurization capability of the system.
PRIORITY DETERMINATION Assumptions Using Oconee-3 as representative of PWRs, PNL assumed" that the dominant core-melt sequence representative of an ATWS event would involve a Power Conversion System (PCS) transient caused by events other than a loss-of-offsite power (LOOP) and failure of the RPS. The LOCA initiator was assumed to be a RCPB pipe rupture with an equivalent 4-inch diameter.
Equipment failures included the containment spray recirculation system and emergency coolant injection and recirculation systems. The containment failure modes were assumed to be similar to other PWR Release Categories involving RCPB ruptures.
The Grand Gulf-1 reactorwas assumed to be representative of BWRs. The dominant core-melt sequence used to model the ATWS event involved transients other than LOOP which require shutdown and a failure to achieve suberiticality. The LOCA initiator was assumed to be a RCPB rupture equivalent to an area of 1 ft2. The equipri, ant failure assumed was loss of the residual heat removal (RHR) system after the LOCA. The containment failure modes were similar to other BWR Release Categories involving a LOCA and subsequent loss of RHR. ;
Freauency Estimate Based on the above assumptions, the reductions in core-melt frequency as a r,esult of modifying the safety relief valves (SRVs) were calculated to be 3.8 x 10# /RY for PWRs and 7.1 x 104/RY for BWRs.
Consecuence Estimate The reduction in public risk was calculated" to be 0.99 man-rem /RY for PWRs and 0.51 man-rem /RY for BWRs. Assuming at least one-half of the plants were affected (45 PWRs and 22 BWRs), with an average remaining life of 28.7 years for PWRs and 27.4 years for BWRs, the total public risk reduction was 1,300 man-rem.
Cost Estimate Industry Cost: SRV modifications were assumed to require approximately 125 man-weeks / plant.
At a rate of $2,270/ man-week, the labor cost for this modification was estimated to be
$284,000/ plant. Equipment was estimated to be $100,000/ plant. For backfit plants, the License Amendment Fee was $4,000. These costs resulted in a backfit cost of $388,000/ plant and a forward-fit cost of $384,000/ plant. For the forward-fit plants, it was assumed that only half of the plants scheduled to begin operation prior to 1986 would require modifications and, subsequent O
12/31/98 1.II.D-2 NUREG-0933
Rsvision 3 to that time, the modifications would be incorporated during initial installation. Based on these estimates, the total industry cost was $21M.
NRC Cost: Development and implementation costs were estimated to be $0.4M and 50.3M, respectively. The development cost was assumed to require 2 man-years of NRC effort and 2 man-years of contractor support. The implementation cost to monitor the hardware modifications at the affected plants was assumed to require 2 man-weeks / plant (36 backfit plants,19 forward-fit plants). Based on these estimates, the total NRC cost was $0.7M.
Total Cost: The total industry and NRC cost associated with the possible solution was $(21 +
0.7)M or $21.7M.
Value/Imoact Assessment Based on an estimated public risk reduction of 1,300 man-rem and a cost of $21.7M for a possible solution, the value/ impact score was given by:
S = 1.300 man-rem
$21.7M
= 60 man-rem /$M CONCLUSION With the exception of potential ATWS events, item II.D.2 was integrated into item II.D.1. Based on the above calculation, the part of item II.D.2 that involved consideration of ATWS events was given a low priority ranking (see Appendix C) in November 1983. In NUREG/CR-5382,'S it was concluded that consideration of a 20-year license renewal period could change the ranking of the issue to medium priority. Further prioritization, using the conversion factor of $2,000/ man-rem approvedsses by the Commission in September 1995, resulted in an impact /value ratio (R) of
$16,666/ man-rem, which placed the issue in the DROP category. Consideration of new information'7" on the phenomenon of "microbonding," submitted by Region IV in April 1997, did not change this conclusion.'7'8 ITEM ll.D.3: RELIEF AND SAFETY VALVE POSITION INDICATION DESCRIPTION This TMI Action Plan" item called for all OLs and applicants for OLs to provide the RCS relief and safety valves with position indication in the control room.
CONCLUSION This item was clarified in NUREG-0737 88 and requirements were issued.
\
12/31/98 1.ll.D-3 NUREG-0933
Rsvision 3 REFERENCES
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
- 64. NUREG/CR-2800, " Guidelines for Nuclear Power Plant Safety issuo Prioritization Information Development," U.S. Nuclear Regulatory Commission, February 1983, (Supplement 1) May 1983, (Supplement 2) December 1983, (Supplement 3) September 1985, (Supplement 4) July 1986, (Supplement 5) July 1996.
- 98. NUREG-0737, " Clarification of TMI Action Plan Requirements," U.S. Nuclear Regulatory Commission, November 1980, (Supplement 1) January 1983. l 1
1563. NUREG/CR-5382, " Screening of Generic Safety Issues for License Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-SS-033 - Preposed Dollar per Person-Rem Conversion Factor, Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
1715. Memorandum to D. Morrison from T. Gwynn, " Periodic Review of Low-Priority Generic I Safety issues," April 16,1997.
1716. Memorandum to T. Gwynn from T. Martin," Periodic Review of Low-Priority Generic Safety issues," July 13,1998.
i 1
0 12/31/98 1.II.D-4 NUREG-0933
Rsvision 3 k
TASK ll.E.2: EMERGENCY CORE COOLING SYSTEM The objectives of this task were to: (1) decrease reliance on the emergency core cooling system (ECCS) for events other than LOCAs; (2) ensure that the ECCS design basis reliability and performance were . consistent with operational experience; (3) reach a better technical understandmg of ECCS performance; and (4) ensure that the uncertainties associated with the prediction of ECCS performance were property treated in small-break evaluations.
ITEM ll.E.2.1: RELIANCE ON ECCS DESCRIPTION Historical Backaround This TMI Action Plan" item called only for the collection of ECCS operating experience. Risk reduction would require that conclusions and recommendations be made and acted upon. Since the stated purpose was to decrease the reliance on ECCS for events other than LOCAs, it was assumed that this item would ultimately lead to the implementation of some hardware modifications.
Safety Sianificance The ECCS of PWRs and BWRs was being actuated for events other than LOCAs. Reliance on the ECCS for events other than LOCAs should be evaluated to ensure that: (1) the ECCS design basis reliability and performance were consistent with operational experience; and (2) a better technical understanding of ECCS performance could be reached.
P_o, ssible Solution in accordance with item II.K.3(17)," licensees were requested to submit a report detailing dates and length of all ECCS outages for the previous 5 years of operation, including causes of the outages. This repost would provide the staff with a quantification of historical unreliability due to test and maintenance outages, which was to be used to determine if a need existed for cumulative outage requirements in the TS. The requested report was to contain: (1) outage dates and duration of outages; (2) cause of each outage; (3) systems or components involved in each outage; and (4) corrective action taken. Test and maintenance outages were to be included in the above listings covering the 5 year period. The licensees were requested to propose changes to improve the availability of ECCS equipment, if needed.
CONCLUSION This issue was covered under item II.K.3(17) which was implemented as part of NUREG-0737."
Thirty out of 36 Technical Evaluation Reports (TERs) were expected from Franklin Institute by September 30,1982; at the time of this evaluation,9 had been received. RRAB/ DST /NRR was to issue SERs to DUNRR for the 30 plants by November 15,1982 and the task was to be closed 12/31/98 1.II.E.2-1 NUREG-0933
Rsvision 3 out by DL/NRR by December 31,1982. By December 31,1982, Franklin institute was expected to issue the remaining 25 TERs, and SERs were to be issued for these plants by RRAB/ DST /NRR by February 15,1983. The final 35 actions were to be closed out by DilNRR by March 31,1983.
ITEM ll.E.2.2: RESEARCH ON SMALL BREAK LOCAs AND ANOMALOUS TRANSIENTS DESCRIPTION Historical Backoround This TMI Action Plan" item was intended to focus research on small breaks and transients. It included experimental research in the loss-of-fluid test (LOFT) Semiscale, BWR full integral simulation test (FIST), and B&W Integral Systems Test facilities, systems engineering, and materials effects programs, as well as analytical methods development and assessments in the code development program. Most of the experimental work for small-break LOCAs (SBLOCAs) was completed in FY 1982 with data analysis to be conducted in FY 1983. Since October 1982, the LOFT project had been supported by an intemational consortium, of which NRC was a member.
Safety Sionificance The primary goal of the small-break and transient research was to improve operator performance during off-normal events. The research on analytical methods development and assessment was directed toward improving existing computer codes, development and application of advanced computer codes for SBLOCA and other accident analysis, and development of a fast, easy to use, engineering analyzer capability. I Possible Solution Part of the program was to examine SBLOCAs and anomalous transients; spe'cifically, the ability of typical process instruments to provide accurate and sufficient information to operating personnel. Advanced control room and diagnostic instrumentation was used in LOFT as part of ;
the augmented operator capabilities program to assess operator needs to mitigate the consequences of LOCA and transient sequences.
PRIORITY DETERMINATION Assumotions Only reduction in operator error during LOCA and transient sequences was assumed. It was also assumed" by PNL that SBLOCAs or transients leading to a LOCA, typically via a stuck-open pressure relief valve, represented the initiating events applicable to this issue. Using Oconee-3 as the representative PWR, these initiators were an S3 LOCA and T,, T2 , or T3 transient coupled with relief valve closure failure (Q). This applied primarily to PWRs; however, the same approach was used for BWRs.
For PWRs, it was assumed that operator errors involved: (1) failure to align suction of high pressure recirculation system to the suction of the low pressure recirculation system; and 12/31/98 1.ll.E.2-2 NUREG-0933
Revision 3 (2) failure to open both containment sump suction valves in the low pressure containment spray recirculation system at the statt of recirculation. For BWRs, itwas assumed that the operator failed to manually initiate the automatic depressurization system (ADS). Operator error in such sequences was assumed to be reduced by one-third as a result of a combination of operator training and improved instrumentation.
Freauency Estimate Based on the above assumptions and using the dominant accident sequences, the reductions in core-melt frequency were calculated" to be 5.2 x 104 /RY for PWRs and 1.8 x 10'7/RY for BWRs.
Consecuence Estimate The reductions in public riskwere calculated to be 15 man-rem /RY for PWRs and 0.5 man-rem /RY for BWRs. Assuming 90 PWRo with an average remaining life of 28.8 years and 44 BWRs with an average remaining life of 27.4 years, the total public risk reduction was 41,000 man-rem for all forward-fit and backfit plants.
Cost Estimate Industry Cost: It was estimated that upgrading operator training and installing upgraded equipment would cost $0.5M/ plant. It was assumed that equipment installation was primarily in the control room, with no increase in radiation exposure, and that only backfit plants were involved. Therefore, assuming 47 PWRs and 24 BWRs, the industry cost was estimated to be $36M. This cost was
/
applied to backfit plants only since the changes resulting from this program would presumably be incorporated into the initial design and licensing of the forward-fit plants.
NRC Cost: This item was an ongoing program; therefore, sunk costs had already been taken in FYs 1980,1981, and 1982. It was estimated that 20% of the FY 1983 LOFT budget was earmarked for the SBLOCA program. This represented approximately $3.1M. In addition, it was assumed that $0.2M would be required to establish new criteria for reactor instrumentation and operator training. NRC annual review was estimated to require an additional 1 man-day /RY. At a rate of $2,270/ week and using the remaining plant life assumed above, this cost was about $1.7M.
Therefore, the total NRC cost was estimated to be approximately $5M. l Total Cost: The totalindustry and NRC cost associated with the possible solution was $(36 + 5)M l 1
or $41M. l Value/ impact Assessment l
Based on an estimated public risk reduction of 41,000 man-rem and a cost of $41M for a possible solution, the value/ impact score was given by:
S = 41.000 man-rem 1
$41M l
= 1,000 man-rem /SM 12/31/98 1.ll.E.2-3 NUREG-0933
Revision 3 CONCLUSION Based on a potential public risk reduction of 41,000 man-rem, a value/ impact score of 1,000 man-rem /$M, and a reduction in core-melt frequency of less than 104 /RY, this issue was given a medium priority ranking (see Appendix C). The test program called forwas completed by the staff and showed that the ECCS will provide adequate core cooling for SBLOCAs and anomalous transients consistent with the single failure criteria of 10 CFR 50, Appendix K. Ongoing thermal-hydraulic research was aimed at defining the degree of uncertainty in the ability of existing analytical models to simulate those transients on full-scale LWRs and not at proving capability.
Thus, this item was RESOLVED and no new requirements were established.eir ITEM ll.E.2.3: UNCERTAINTIES IN PERFORMANCE PREDICTIONS DESCRIPTION Historical Backaround Small-break LOCA analyses performed by LWR vendors to develop operator guidelines had shown that large uncertainties may exist in system thermal-hydraulic response due to modeling assumptions orinaccuracies. It was necessary to establish that these assumptions orinaccuracies were properly accounted for in determining the acceptability of ECCS performance pursuant to Appendix K of 10 CFR 50.
The reason behind this TMI Action Plan" item was that, historically, the SBLOCA analyses were never reviewed by the NRC in the depth and detail with which the large-break analyses were reviewed. One of the obvious lessons of the TMI-2 accident was that SBLOCAs are much more likely to occur and, thereforc, a highly detailed re-review of the small-break analyses might have been appropriate.
Safety Sionificance SBLOCAs do not automatically result in rapid depressurization of the primary system. The more complicated blowdown makes it more difficult to predict ECC injection flow rates, water level, and many other parameters as a function of time. Moreover, there are many more possible locations for the break. In addition, the possibility of unexpected thermal-hydraulic phenomena cannot be ruled out. Since the SBLOCA analyses must conservatively bound a plant's response to all possible small brecks, all of these effects should be understood as well as possible.
Possible Solution The proposed solution in NUREG-0660" called for NRR to issue instructions to holders of approved ECCS evaluation models to evaluate the uncertainty of small-break ECCS performance calculations; NRR was to evaluate these uncertainties. If changes were needed in the existing analysis methods to properly account for these uncertainties, recommendations were to be made to the Commission to adopt such changes. Ultimately, the adoption of these changes would result in changes to the analyses upon which plant TS were based. This could result in seme restrictions on power level under certain circumstances.
O l
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Rsvision 3 C PRIORITY DETERMINATION d
l Freauency Estimate According to WASH-1400 estimates, small breaks (2 in. to 6 in. diameter) are expected to occur at a rate of 3 x 104 event /RY; very small breaks (0.5 in. to 2 in. diameter) are estimated to occur at a rate of 104 event /RY. Should such an event occur, it was estimated (based purely on judgment) that there may be a 10% chance of the actual peak cladding temperatures exceeding the temperatures predicted by the 10 CFR 50, Appendix K calculation due to the modeling uncertainties mentioned above.
However, in addition to the modeling conservat.sm, the 10 CFR 50, Appendix K calculations assumed the worst case single failure. Moreover, the small break analysis was very seldom limiting; usually the calculated small break peak cladding temperatures are about 400*F below the 2200'F Appendix K limit. Finally, a plant does not normally operate with the LOCA parameters (Fo, MAPLHGR, etc.) at their limits.
Because the specific worst-case single failure varied for different plants, it was not practical to use fault trees to calculate the probability of such a failure. However, some perspective was gained by examining the following estimated failure rates from Appendix 11 of WASH-1400:
PWR HPSI 1.2 x 10-2/ demand PWR Emergency Power 104/ demand BWR HPCI 9.8 x 10-2/ demand BWR Emergency Power 104/ demand The frequency of a system failure severe enough to approximate the Appendix K single failure assumptions was estimated to be, at most,10-'/ demand. Given a small LOCA, a modeling uncertainty, and something approximating the worst-case single failure, the actual peak cladding temperature would be greater than that calculated by the analyses. However, there was still considerable margin to significant core damage because:
P (1) The small-break analysis is rarely limiting. Usually there is about a 400 F margin between the calculated small-break peak cladding temperature and the 2200 F limit.
(2) Most plants operate well within their LOCA limits (i.e., are not "LOCA-limited").
(3) To get severe damage, a significant amount of cladding must achieve a temperature significantly higherthan 2200 F. The case of the hottest point of the core barely exceeding the temperature limit does not automatically imply severe damage.
These three considerations were summed by assuming that there was, at most, a 5% chance of significant core damage given a small LOCA, a model problem, and a near-worst-case single failure. Putting all this together, the frequency of events with significant core damage was estimated to be, at must, about 7 x 10# /RY.
s 12/31/98 1.ll.E.2-5 NUREG-0933
Revision 3 Consecuence Estimate if cladding temperatures rise significantly above 2200 F in a large portion of the core, the likely result would be a bed of debris. It was assumed that there was a 10% chance of a core-melt and a 90% chance of widespread cladding failure but no fuel melting. Neither of these fit readily into the WASH-14003e Release Categories. The core-melt case was approximated with 5 x 10e man-rem (which is greater than or approximately equal to the consquences of PWR-1 through PWR-7 and BWR-1 through BWR-4), and the non-core-melt case by 120 man-rem (which bounds PWR-9 and BWR-5).
Cost Estimate Industry Cost it was estimated" that 15 staff-years and $1M of computer time would be required to perform the studies. In addition, 3 staff-months per operating plant were needed to implement procedural and TS changes. Since there were 70 plants operating, the estimated total direct industry cost was $4.25M (The 57 plants under construction at the time of this evaluation would not require implementation costs since the new analyses would displace analyses which would have been required in any case.)
In addition to the direct cost, there was an indirect cost due to the effect of further restricting operating parameters. Using the eariier assumptions that there was a 10% chance of finding a non-conservatism and a 5% chance of being SBLOCA-limited, and assuming further that at least a 1% power reduction resulted under such circumstances, the indirect costs averaged at least
$5,500/RY. There were 43 operating PWRs with a cumulative experience of 350 RY and 27 BWRs with a cumulative experience of 260 RY. Adding the 36 PWRs and 21 BWRs that were under construction and assuming a plant life of 40 years, there were 4,470 RY remaining. Thus, !
the indirect cost was $24.6M and the total industry cost was $(4.25 + 24.6)M or $28.85M.
NRC Cost: It was estimated that 15 staff-years and $100,000 would be necessary for the staff to review the studies; in addition, the 70 backfit plants would require one staff-month each. (Again, the 57 plants under construction would not need a significant amount of extra review effort since the new reviews would displace the reviews of other analyses that would have been submitted.)
Thus, NRC costs were estimated to be about $1.2M.
Total Cost: The total industry and NRC cost associated with the possible solution was $(28.85 +
1.2)M or 30.05M.
Value/ impact Assessment Based on an estimated public risk reduction of 1,565 man-rem and a cost of $30.05M for a possible solution, the value/ impact score was given by:
S = 1.565 man-rem
$30.05M
= 52 man-rem /$M O
12/31/98 1.ll.E.2-6 NUREG-0933
1 Rsvision 3 !
l h CONCLUSION j Based on the safety importance and value/ impact score above, this issue had a low priority ranking. In addition, RSB/DSI/NRR had noted that much of the technical concem of the issue was automatically being investigated" in the implementation of item li.K.3(30) which was in progress at the time of the initial evaluation of the issue in November 1983. In order to prevent duplication of effort and because the work on item II.K.3(30) was in progress, the issue was given a low priority ranking (see Appendix C). In NUREG/CR-5382,'" it was concluded that consideration of a 20-year license renewal period did not change the priority of the issue. Further prioritization, using the conversion factor of $2,000/ man-rem approved'*" by the Commission in September 1995, resulted in an impact /value ratio (R) of $19,230/ man-rem which placed the issue in the DROP category. )
REFERENCES '
- 16. WASH-1400 (NUREG-75/014), " Reactor Safety Study, An Assessment of Accident Risks )
in U.S. Commerical Nuclear Power Plants," U.S. Atomic Energy Commission, October 1975.
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Reguatory Commission, May 1980, (Rev.1) August 1980.
- 98. NUREG-0737, " Clarification of TMl Action Plan Requirements," U.S. Nuclear Regulatory Commission, November 1980, (Supplement 1) January 1983.
817. Memorandum for W. Dircks from R. Minogue, " Closeout of TMI Action Plan Task II.E.2.2,
'Research on Small Break LOCA's and Anomalous Transients,'" July 25,1985.
' 1563. NUREG/CR-5382, " Screening of Generic Safety issues for License Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294)," i September 18,1995.
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l TASK ll.E.5: DESIGN SENSITIVITY OF B&W REACTORS f The objective of this taskwas to reduce the sensitivity of B&W plants to feedwater transients, with emphasis on the overcooling transients that had been observed at B&W operating plants.
ITEM ll.E.5.1: DESIGN EVALUATION DESCRIPTION Historical Backaround 1
The NRC staff concluded that B&W reactors exhibited unique sensitivity to secondary system transients (both undercooling and overcooling events). Therefore, B&W plants under construction I were required to propose recommendations on hardware and procedure changes relative to the need for methods for damping primary system sensitivity to perturbations in the once-through steam generator (OTSG). This issue also considered the backfitting of the recommendations on operating plants.
Safety Sianificance The safety significance of this TMl Action Plan item ** was the same as that for item II.E.5.2, i.e., i the perception of what constitutes acceptable response to transients.
Possible Solution All B&W plants under construction were required [10 CFR 50.54(f)] to provide recommendations to reduce plant sensitivity.* The recommendations (with proposed modifications) were submitted for NRC review. The staff also evaluated the modifications proposed by the applicants for possible backfit to operating plants.'"'"' The staff concluded that the portion of this issue that dealt with plants under construction was completed with the issuance of the Midland-1&2 SER which evaluated the modifications.'"'"d The other B&W plants under construction were to be i evaluated as part of the normallicensing review.
The portion of the issue which dealt with backfit considerations was also completed.'58 *d' Specifically, the staff concluded that the Midland modifications would be effective in reducing both the frequency and severity of overcooling transients and recommended that similar modifications be made at operating B&W plants. The staff also concluded that the following related activities
. were underway:
(1) Operating B&W plants were implementing upgrades to meet NUREG-0737.**
(2) Issue A-47, " Safety implications of Control Systems," was addressing steam generator overcooling / overfilling as it related to control system failures.
12/31/98 1.II.E.5-1 NUREG-0933
Revision 2 (3) The staff was also pursuing resolution of overcooling events (steam bubble formation / natural circulation interruption) on a generic basis with the B&W Owners' Group
[NUREG-0737," Item II.K.3(30)].
(4) Consideration of pressurized thermal shock (PTS) concerns relating to overcooling were being addressed by the staff as part of the resolution of Issue A-49," Pressurized Thermal Shock."
CONCLUSION Based on the above, the staff concluded that the B&W-designed operating reactors had responded to staff concems regarding the frequency of overcooling and steam generator overfill events by implementing plant modifications. The adequacy of these modifications were to be confirmed by other ongoing programs. Thus, this item was RESOLVED and requirements were established.
ITEM ll.E.5.2: B&W REACTOR TRANSIENT RESPONSE TASK FORCE DESCRIPTION Historical Backaround After TMI-2, the NRC staff investigated'55 the response of B&W reactors to transients and q determined that, in their opinion, they were overly responsive to certain transients. This responsiveness or sensitivity was attributed to a number of design and operational features including the small secondary water inventory in the steam generator, the small pressurizer volume, the pilot-operated relief valve (PORV) set-point, and the high pressure injection (HPI) set- !
points. As a result of the investigation, a number of recommendations were made forimproving the plant response.'55 ,
1 The recommendations covered a number of design changes and operational considerations.
DST /NRR provided a prioritization for the recommendationsssein August 1980. A numberof these recommendations (referred to as Category A items) had aiready been implemented (orwere being implemented) for the B&W operating plants.'55'57 The other recommendations (referred to as Category B items) had not been issued as requirements, although a number of them had been implemented by some licensees with B&W plants as part of their own investigations.
l l
Safety Sianificance ;
i The safety significance of this TMI Action Plan" item depended on the perception of what l constitutes acceptable response to transients. NRC requirements were outlined in the SRP" and l all plants were required to meet these, as a minimum. It was suggested'58 by DSI/NRR that l additional performance criteria were necessary to more restrict the plants' response to transients t and, as a result, limit the potential for plant damage.
i t
12/31/98 1.ll.E.5-2 NUREG-0933 l l
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Rsvision 2 Possible Solution The technical resolution to this issue was defined in NUREG-0667.* It was suggested'" that implementing the resolution required additional specific. tion of the staffs performance criteria for transient response. (Existing critena were contained in the SRP.") Therefore, DSI/NRR proposed
- that a uniform requirement in the form of criteria be issued by the NRC to ensure that adequate steps were taken by all B&W plants. Specifically, the recommended criteria were:
(1) ECCS actuation or loss of pressurizerlevel indication should not normally occur following a reactor trip or main feedwater control failure.
(2) Credit for operator schon to mitigate overcooling events should be consistent with the guidelines of ANSI /ANS-58.8."
(3) Steam generators should be protected from overfill from main or auxiliary feedwater flow to limit overcooling. This equipment should be safety grade if flooding of the steam lines is an unanalyzed event.
CONCLUSION Based on a DST /NRR evaluation
- of the issue, it was recommended that implementation would be best accomplished by issuance of a staternent of NRC's performance criteria for transients. It was also recommended that the first two criteria and accompanying value/ impact statements be submitted to CRGR for review. The third criterion was included in issues A-47 and A-49. Thus, the issue was RESOLVED and requirements were established.""7 REFERENCES
- 11. NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," U.S. Nuclear Regulatory Commission, (1st Edition) November 1975, (2nd Edition) March 1980, (3rd Edition) July 1981.
- 45. ANSI /ANS-58.8, " Time Response Design Criteria for Nuclear Safety Related Operator Actions," American Nuclear Society,1984.
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
i
- 98. NUREG-0737, " Clarification of TMI Action Plan Requirements," U.S. Nuclear Regulatory l Commission, November 1980, (Supplement 1) January 1983.
154. NRC Letter to Construction Permit Holders of B&W Designed Facilities, October 25,1979.
155. NUREG-0667, " Transient Response of Babcock & Wilcox Designed Reactors," U.S.
Nuclear Regulatory Commission, May 1980.
156. Memorandum for H. Denton from D. Eisenhut, "NUREG-0667, Transient Response of Babcock & Wilcox Designed Reactors, Implementation Plan," June 3,1981.
12/31/98 1.ll.E.5-3 NUREG-0933
Revision 2 157. Memorandum for D. Eisenhut from G. Lainas, " Status Report on implementation of NUREG-0667 Category A Recommendations," December 15,1981. i 158. Memorandum for H. Denton from R. Mattson, " Review of Final Report of the B&W Reactor Transient Response Task Force (NUREG-0667)," August 8,1980.
159. Memorandum for S. Hanauer from R. Mattson, " Design Sensitivity of B&W Reactors, item ll.E.5.1 of NUREG-0660," February 26,1982. t 160. Memorandum for R. Mattson from S. Hanauer, " Design Sensitivity of B&W Reactors,"
June 21,1982.
443. Memorandum for W. Dircks from R. Mattson, " Closeout of NUREG-0660 Item II.E.5.1, Design Sensitivity of B&W Plants for Operating Plants," March 15,1983.
656. Memorandum for W. Dircks from H. Denton, " Closeout of TMI Action Plan Task II.E.5.2, Transient Response of B&W Designed Reactors," September 28,1984.
657. Memorandum for D. Crutchfield from D. Eisenhut, "TMI Action Plan Task II.E.5.2,"
November 6,1984.
l O
J l
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1 Ol1 l
12/31/98 1.ll.E.5-4 NUREG-0933 i
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TASK ll.E.6: IN SITU TESTING OF VALVES The objective of this task was to evaluate whether existing requirements for valve testing provided )
adequate assurance of performance under design conditions. l ITEM ll.E.6.1: TEST ADEQUACY STUDY DESCRIPTION Historical Backaround The purpose of this TMl Action Plan" item was to establish the adequacy of existing requirements for safety-related valve testing, it recommended a study which would result in recommendations for attemate means of verifying performance requirements.
Safety Sianificance Valve performance is critical to the successful funcboning of a large number of a plant's safety systems.
Possible Solution
\
It could be assumed that a study would be conducted for both PWRs and BWRs and that it could result in reco.mmendations for additional testing and/or maintenance on all safety-related valves.
A program to implement the recommendations would then be required at all plants.
PRIORITY DETERMINATION Assumptions in an analysis of this issue by PNL," it was assumed that all safety-related valves would be affected by resolution of the issue. Then, since all the dominant accident sequences (of Oconee-3 and Grand Gulf-1, the repiesentative plants) involved failures of such valves, the sequences themselves were assumed to be directly affected, it was assumed that the new prop am would produce a reduction of 5% in the frequencies of the affected accident sequences (those that involved safety-related valves).
Frecuency Estimate it was determined" that all accident sequences for Oconee-3, except the following, involved safety-related valves and were thus assumed to be affected: T2MLUO, T2KMO, T,(B3)MLU, T3MLUO, and T 3MLUO. For Grand Gulf-1, the only exception was T 2sC.
For all the affected parameters, the base case frequency was taken as the original value. The adjusted case frequency was then calculated by the 5% reduction. The core-melt frequency 12/31/98 1.II.E.6-1 NUREG-0933 1
Rsvision 2 reduction was then calculated to be 3 x 104/RY and 10 4/RY for Oconee-3 and Grand Gulf-1, respectively. !
Conseauence Estimate Based on the 5% reduction, the public risk reduction was calculated to be 7.1 man-rem /RY and 7.8 man-rem /RY for Oconee-3 and Grand Gulf-1, respectively. The average remaining lives of the j 95 affected PWRs and the 49 affected BWRs were calculated to be 28.2 years and 26.2 years, respectively. This resulted in a potential risk reduction of 1.9 x 104 man-rem for PWRs and 10d man-rem for BWRs. Thus, the total risk reduction associated with this issue was approximately 3 x 10d man-rem.
Cost Estimate Industry Cost: Itwas estimated that the implementation effort for engineering, etc., would be about i 10 man-weeks / plant for PWRs and 8 man-weeks / plant for BWRs. (The difference was due to the ,
fewer number of affected valves in a BWR.) The cost was then calculated as follows: l i
PWRs: (10 man-weeks / plant)($2,000/ man-week) = $20,000/ plant )
BWRs: (8 man-weeks / plant)($2,000/ man-week) = $16,000/ plant j i
For the 95 PWRs and 49 BWRs, this cost amounted to $2.7M.
l The annual industry effort for operations and maintenance was estimated to be 16 man-weeks /RY for PWRs and 12 man-weeks /RY for BWRs with resultant costs of $16,000/RY and $12,000/RY for PWRs and BWRs, respectively. Forthe 95 PWRs with an average remaining life of 28.2 years, the cost was approximately $42.9M. For the 49 BWRs with an average remaining life of 26.2 years, the cost was approximately $15.4M.
Thus, the total industry cost to implement the possible solution to this issue was $(2.7 + 42.9 +
15.4)M or $61M.
NRC Cost: NRC labor for development of the solution for PWRs was estimated to be 1 man-year.
' Implementation of the solution was estimated to take 1 man-week / plant. Development of the solution for BWRs was estimated to be 0.5 man-year. Implementation time expended was estimated to be the same as for PWRs. Therefore, the estimated NRC costs were $0.43M.
It was also estimated that NRC labor for periodic review of operation and maintenance of the solution would be 1 man-week /RY for PWRs and 0.5 man-week /RY for BWRs. This translated into
$2,000/RY and $1,000/RY, respectively, for all plants for a cost of $6.7M. Thus, the total NRC cost was $(0.43 + 6.7)M or $7.1M.
Total Cost: The total industry and NRC cost to resolve this issue was estimated to be $(61 +
7.1)M or $68.1M.
O 12/31/98 1.II.E.6-2 NUREG-0933
l Ravision 2 {
l Value/ impact Assessment Based on a potenbal risk reduction of 3 x 10d man-rem and an estimated implementation cost of
$68.1M, the value/ impact score was given by:
S = 3 x 10dman-rem i
$68.1M
= 440 man-rem /$M Uncertainty The value/ impact score was significantly influenced by the assumption that a 5% frequency reduction could be obtained; this number was highly judgmental.
Other Considerations (1) Occupational dose would lower (significantly) this value/ impact score because the labor required in a radiation zone would be significant. The estimated occupational dose from ,
performing this periodic testing was about 24 man-rem /RY for PWRs and 18 man-rem /RY for BWRs. Over the life of a plant, the overall (total) occupational dose was estimated to be 8.9 x 10d mar.-rem.
(2)- Occupational risk reduction due to accident avoidance was concluded to be small and accident avoidencu costs, although large when considered in relation to the other costs, would not significantly change the score.
CONCLUSION Based on the value/ impact score and the additional considerations, this issue was given a medium priority ranking and was laterdivided into four parts during resolution: (1) pressure isolation valves; (2) check valves; (3) reevaluation of thermal-overioad protection provisions of Regulatory Guide 1.106121s for MOVs; and (4) in-situ testing of MOVs.
The investigation of altematives to leak rate testing of pressure isolation valves, including check valves, was integrated into the resolution of issue 105, " Interfacing Systems LOCA." These attematives included non-intrusive methods to detect check valve disk position and motion, as well )
as surveillance of intemal parts by various means. Any new issue regarding testing of check i valves that may be identified in the future will be prioritized as a new generic issue. The results l of the staff's study of MOV thermal overload protecSn were published in NUREG-1296.121s The staff concluded that, although misinterpreted by the industry at times, the guidelines in Regulatory Guide 1.106t21s were adequate. Several suggestions for improving MOV thermal overload protection were outlined in NUREG-1296.121e in addition, letters were sent to the pertinent IEEE and ASME subcommittees encouraging the development of standards for MOV thermal overload protection. In-situ testing and surveillance of check valves was being addressed by an industry effort; in-situ testing of MOVs was resolved with the issuance of Generic Letter 89-10.5217 Thus, this issue was RESOLVED and requirements were established.521s 12/31/98 1.ll.E.6-3 NUREG-0933
Revision 2 REFERENCES
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
- 64. NUREG/CR-2800, " Guidelines for Nuclear Power Plant Safety issue Prioritization Information Development," U.S. Nuclear Regulatory Commission, February 1983, (Supplement 1) May 1983, (Supplement 2) December 1983, (Supplement 3)
September 1985, (Supplement 4) July 1986, (Supplement 5) July 1996.
1215. Regulatory Guide 1.106, " Thermal Overload Protection for Electric Motors on Motor-Operated Valves," U.S. Nuclear Regulatory Commission, November 1975, (Rev.1)
March 1977.
1216. NUREG-1296," Thermal Overioad Protection for Electric Motors on Safety-Related Motor-Operated Valves - Generic issue ll.E.6.1," U.S. Nuclear Regulatory Commission, June 1988.
1217. NRC Letter to All Licensees of Operatiag Power Plants and Holders of Construction Permits for Nuclear Power Plants, " Safety-Related Motor-Operated Valve Testing and i Surveillance (Generic Letter No. 89-10) - 10 CFR 50.54(f)," June 28,1989, (Supplement
- 1) June 13,1990, (Supplement 2) August 3,1990, (Supplement 3) October 25,1990, (Supplement 4) February 12,1992, (Supplement 5) June 28,1993, (Supplement 6) March 8,1994.
1218. Memorandum for V. Stello from E. Beckjord, "Close-out of Generic issue ll.E.6.1, 'In Situ )
Tes+Jng of Valves.'" June 30,1989.
I O'
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l TASK ll.F: INSTRUMENTATION AND CONTROLS l The objective of this task was to provide instrumentation to monitor plant variables and systems dunng s7d following an acadent. Indications of plant variables and status of systems important
- to safety are required by the plant operator (licensee) during accident situations to:
(1) provide information needed to permit the operator to take pre-planned manual actions to accomplish safe plant shutdown; (2) determine whether the reactor trip, engineered safety features systems, an manually-initiated systems are performing their intended functions (i.e., reactivity control, core cooling, maintaining reactor coolani system integnty, and maintaining containment integrity);
(3) provide information to the operatui that will enable him to determine the potential for a breach of the barriers to radioactivity release (i.e., fuel cladding, reactor coolant pressure boundary, and containment) and if a barrier has been breached; (4) fumish data for deciding on the need to take unplanned action if an automatic or manually- 1 initiated safety system is not functioning property or the plant is not responding properly i to the safety systems in operation; )
allow for early indication of the need to initiate action necessary to protect the public and (5) for an estimate of the magnitude of the impending threat;
)
(6) improve requirements and guidance for classifying nuclear power plant instrumentation control and electrical equipment important to safety.
4 LTEM ll.F.1: ADDITIONAL ACCIDENT MONITORING INSTRUMENTATION This item was clarified in NUREG-0737," requirements were issued, and MPAs F-20, F-21, F-22, F-23, F-24, and F-25 were established by DL for implementation purposes.
ITEM 11 F.2: IDENTIFICATION OF AND RECOVERY FROM CONDITIONS LEADING TO INADEQUATE CORE COOLING This item was clarified in NUREG-0737," requirements were issued, and MPA F-26 was established by DL for implementation purposes.
ITEM ll.F.3: INSTRUMENTS FOR MONITORING ACCIDENT CONDITIONS i
DESCRIPTION 55 Prior to the TMI-2 event, the August 1977 version of Regulatory Guide 1.97 had been used as guidance during licensing reviews, item ll.F.3 called" for this regulatory guida to be updated to include the TMI-2 concems.
12/31/98 1.II.F-1 NUREG-0933
Revision 3 CONCLUSION After the TMI 2 event, Task II.F of the TMI Action Plan" addressed several concems regarding the availability and adequacy of instrumentation to monitor plant variables and systems during and following an accident. Revision 2 to Regulatory Guide 1.9755was published in December of 1980 and implementation was carried out as discussed in SECY-82-111'5' and a letter 37
' issued to all licensees of operating reactors. Thus, this item was RESOLVED and new requirements were established.
ITEM ll.F.4: STUDY OF CONTROL AND PROTECTIVE ACTION DESIGN REQUIREMENTS DESCRIPTION Historical Backaround After the TMI-2 event, the SpecialInquiry Group made recommendationsie ' for the staff to study three items in the area of control and protection systems. These were: (1) automatic reactor protection actions should be derived, to the degree possible, from independent process variables; (2) automatic actions through coincidence of independent process variables should be limited, to j the degree possible, for non-reactor protection functions; (3) control circuit components should be designed and periodically tested at expected degraded power supply conditions to ensure that they are capable of performing theirintended function.
I Safety Sianificance The report concluded that improvements in these areas may help prevent specific occurrences !
which were noted upon evaluation of the TMI-2 event. l l
Possible Solutions This TMl Acticn Plan" item addressed the performance of a study that could indicate potential l deficiencies and identify possible fixes which could be incorporated as design criteria in the SR P." i Industry would then be required to meet these criteria.
{
PRIORITY DETERMINATION No attempt was made to estimate a value/ impact score for this issue. It appeared that the non-specific nature of the recommendations (i.e., use of words like "to the degree possible") would I require a large amount of additional study prior to defining any specific implementation I requirements. Therefore, neither potential risk reduction or costs could be estimated. The following considerations were taken into account.
(1) The first criterion, to a large degree, was typically addressed by existing protection l systems. The use of a number of different plant parameters to initiate the protection l
system was an indication of the application of this criterion. There may have been instances in different plant designs where, for certain ever ts, this criterion had not been adequately addressed; however, it was believed that these were isolated instances.
Furthermore, the ATWS rule, which included NUREG-0460* requirements, addressed monitoring ofindependent process variables. As another consideration, protection system 12/31/98 1.ll.F-2 NUREG-0933
Revision 3
[
' design requirements were expected to undergo another review as a result of preparation of a Regulatory Guide to endorse IEEE Std. 603-1977.200 (2) The second criterion addressed non-protection systems. At the time this issue was initially evaluated, the staff did not have detailed design criteria for these systems (typically referred to as " control systems") in the SRP." It was believed that, if any criteria were to be included, they would be the result of a comprehensive program such as the existing program addressing Issue A-47, " Safety implications of Control Systems."
(3) One part of the third criterion was addressed in SRP" Section 3.11, " Environmental Qualification of Equipment." Specifically, safety-related components are designed for performance at varying power supply conditions. Typically, they are initially tested to these conditions as part of their qualification program. The other part of the third criterion was not required at the time this issue was evaluated. Under conditions with offsite power feeding all plant components, it could be postulated that redundant components could experience some degraded power supply conditions; however, this concem was addressed through various plant fixes as part of their degraded grid analysis. Under conditions with onsite power feeding the components, the independence of the systems would prevent redundant components from experiencing degraded power.
CONCLUSION Based on the considerations listed above, this issue was placed in the DROP category.
ITEM ll.F.5: CLASSIFICATION OF INSTRUMENTATION. CONTROL. AND ELECTRICAL EQUIPMENT )
DESCRIPTION Historical Backaround After the TMI-2 event, the staff recommended" that the existing method of classifying instrumentation, control, and electrical equipment needed revision to allow graded criteria that would more closely correspond to the equipment's importance to safety.
Safety Sionificance Such a grading could place emphasis on improvements in the non-class 1 E systems which could affect core-melt frequency. It could also allow more design flexibility and result in potentially more cost-effective electrical, instrumentation, and control system designs.
Possible Solution it was recommended that the NRC, in conjunction with IEEE, develop a standard which would provide a classification approach based on the level of importance to safety of equipment. The standard would then be endorsed by a Regulatory Guide. Utility conformance to important criteria such as redundancy, reliability, etc., for selected systems would be mandated.
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l l
Rsvision 3 i
PRIORITY DETERMINATION l Assumotions A program to classify and upgrade non-1E instrumentation, controls, and electrical systems was 4 assumed to improve balance-of-plant system reliability and thus reduce transient frequencies.
Based on EPRI transient data, 7 a number of transient categories and frequencies of interest were identified.
In a PNL assessment ** of this issue, it was assumed that 50% of all these transients were attributable to instrumentation, control, and electrical system failures. Then it was assumed that
]
resolution of this issue would result in about a 10% reduction in such failures. j Freauency Estimate i
The reduction assumed above translates into about a 6% reduction in transients (other than loss of offsite power) for PWRs and a 4% reduction in transients for BWRs. Therefore, the 6%
reduction was divided between the T2 and T3transients for PWRs in the Oconee-3 risk equations. I The 4% reduction was applied to the T23transients for BWRs in the Grand Gulf-1 equations. This {
resulted in reductions in core-melt frequency of 2.1 x 10 4/RY for PWRs and 9 x 10-7/RY for BWRs.
Conseauence Estimate The above data translated (assuming a population density at 340 people / square-mile) to a per plant reduction in public risk of 5.6 man-rem /RY for PWRs and 7 man-rem /RY for BWRs.
Assuming 90 PWRs with an average remaining life of 28.8 yrs and 44 BWRs with an average i remaining life of 27.4 yrs, the total public risk reduction was estimated to be 23,000 man-rem. l Cost Estimate industry Cost: An estimate of costs forimplementing improved non-1E systems was based on the installation cost ($1M) of a safety parameter display system (SPDS) at Yankee Rowe. The SPDS is considered a non-1E system which includes certain design features beyond those of a typical non-1 E system. It was assumed that classification and upgrading of all remaining non-1 E systems would represent a similar cost of $1M/ plant, divided evenly between equipment costs and manpower costs for backfit plants. Forward-fit plants should only require additional equipment costs. Total industry cost would then be (based on 47 backfit and 43 forward-fit PWRs and 24 backfit and 20 forward-fit BWRs) about $100M.
NRC Cost: Since the IEEE Trial Use Guide P-827,2 '"A Method for Determining Requirements for Instrumentation, Control and Electrical Systems important to Safety," had been released, the NRC cost for development was considered minimal (i.e., on the order of 0.5 man-year). The cost for support of the resolution was believed to be potentially significant and was assumed to be 1 man-year / plant with a resultant cost of $13.4M.
Total Cost: The totalindustry and NRC cost associated with the possible solution to this issue was estimated to be $(100 + 13.4)M or $113.4M.
O 12/31/98 1.ll.F-4 NUREG-0933
Rsvision 3 p Value/imoact Assessment' Based on a potential public risk reduction of 23,000 man-rom and an estimated cost of $113.4M for a possible solution, the value/irnpact score was given by:
S = 23.000 man-rom
$113.4M
= 200 man-rem /$M.
Uncertainties (1) The estimates of the transient frequency reductions were subject to many assumptions )
which themselves are uncertain. 1 (2) Cost estimates were extremely hard to calculate without a clearer fix in mind.
l (3) NRC review time would also vary based on the actual fix involved. l l
Other Considerations 1 I
(1) A significant industry cost saving (which would outweigh the industry cost) could be l calculated based on a saving in plant outage time resulting from improved non-1 E system reliability. For example, if it were assumed that non-loss of offsite power transients would O be reduced from 7 to 6.58/RY with a loss of one day of power generation per transient, Q then unscheduled outages would be reduced by 0.42 day /RY. Based on a replacement power cost of $300,000/ day, the cost savings would be (0.42 day /RY)($300,000/ day) or
$130,000/RY. For 134 plants with a remaining lifetime of 30 years, the total cost savings would be (134 plants)(30 years)($130,000/RY) or $523M.
(2) A draft of IEEE P-827 "A Method for Determining Requirements for instrumentation, Control and Electrical Systems important to Safety," was issued.
(3) RES was in the process of developing a draft regulatory guide for the classification of systems important to safety that would provide for a Class 2E instrumentation, control, and electrical power system and equipment. This effort was proceeding independently of the IEEE/ANS efforts.
)
CONCLUSION l Based on the favorable value/ impact score, the effort expended up to the time of the above i analysis, and the potential risk reduction and cost saving, this issue was given a medium priority ranking. However, after further evaluation, it was reclassified as a Licensing Issue based on the continuation of the staff's support of the IEEE efforts to develop a standard to define requirements for equipment and systems that are not safety-related, but are sufficiently important to safety to warrant special consideration."
The Draft Trial Use Guide P-827 was developed by IEEE butwas never published; the project was withdrawn in 1983. Under a separate activity, BNL, under contract with the NRC, attempted to l
12/31/98 1.ll.F-5 NUREG-0933
Revision 3 develop a methodology to address the classification issue. In both instances, these activities were terminated due to a lack of agreement on the scope and content of the issue. ,
in 1989, the IEEE/NPEC Working Group SC 6.2 continued to develop a Position Paper on this issue that would only address the possible benefits of establishing a graduated classification program arid would provide a list of attributes that would be prudent to incorporate into such a program. However, the Position Paper was not expected to establish any specific guidelines for an acceptable program.
Based on the lack of new plants being constructed, the industry's reluctance to change their existing classification documentation, and the previous efforts both by the NRC staff and the industry to develop a classification methodology, the staff concluded that no additional NRC action should be taken. Thus, the issue was resolved."87 REFERENCES
- 11. NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," U.S. Nuclear Regulatory Commission, (1st Edition) November 1975, (2nd Edition) March 1980, (3rd Edition) July 1981.
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev. y August 1980.
- 55. Regulatory Guide 1.97, " Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," U.S. Nuclear Regulatory Commission, December 1975, (Rev.1) August 1977, (Rev. 2) December 1980, (Rev. 3) May 1983.
- 98. NUREG-0737, " Clarification of TMI Action Plan Requirements," U.S. Nuclear Regulatory Commission, November 1980, (Supplement 1) January 1983. ,
151. SECY-82-111, " Requirements for Emergency Response Capability," March 11,1982.
161. NUREG/CR-1250,"Three Mile Island: A Report to the Commission and to the Public," U.S.
Nuclear Regulatory Commission, January 1980.
200. IEEE Std. 603, " Standard Criteria for Safety Systems for Nuclear Power Generating )
Stations," The Institute of Electrical and Electronics Engineers, Inc.,1980. J l
307. EPRI NP-2230, "ATWS: A Reappraisal, Part 3," Electric Power Research Institute,1982.
376. NRC Letterto 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.
704. NUREG-0460, " Anticipated Transients Without SCRAM for Light Water Reactors,"
U.S. Nuclear Re0ulatory Commission, (Vol.1) April 1978, (Vol. 2) April 1978, (Vol. 3) l December 1978, (Vol. 4) March 1980. I O1 12/31/98 1.II.F-6 NUREG-0933
i Ravision 3
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'V 1105. Memorandum for T. Speis from G. Ariotto, " Generic issues Program," January 14,1988.
i 1187. Memorandum for V. Stello from E. Beckjord, " Closeout of Generic issue ll.F.5, '
' Classification of instrumentation, Control and Electncal Equipment,"' May 5,1989.
1 1
l 4
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I Rzvision 1 O
TASK ll.G: ELECTRICAL POWER I I
The objective of this task was to increase the reliability and diversification of the electrical power supplies for certain safety-related equipment.
1 ILEM ll.G.1: POWER SUPPLIES FOR PRESSURIZER RELIEF VALVES. BLOCK VALVES. AND l LEVEL INDICATORS DESCRIPTION This TMi Action Plan" item called for licensees to develop and implement procedures and modifications to upgrade motive and control components to safety-grade criteria. Motive and ;
control components of PORVs and PORV block valves were to have the capability of being supplied either from the offsite power source or from the emergency power source when offsite power was not available. Motive and control power connections to the emergency buses for the PORVs and their associated block valves were to be through devices that had been qualified in accordance with safety-grade requirements. The pressurizer level indication instrument channels were to be powered from the vital instrument buses that had the capability of being supplied either from the offsite power source or from the emergency power source when offsite power was not avaliable.
CONCLUSIOS This item was clarified in NUREG-0737" and requirements were issued.
REFERENCES
.48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
l
- 98. NUREG-0737, " Clarification of TMI Action Plan Requirements," U.S. Nuclear Regulatory Commission, November 1980, (Supplement 1) January 1983. ]
12/31/98 1.II.G-1 NUREG-0933
I Rsvision 3 TASK ll.H: TMI-2 CLEANUP AND EXAMINATION The objechves of this task were to: (1) maintain safety and minimize environmental impact of post-accident operation and cleanup of TMI-2; and (2) obtain and factor into regulatory programs safety-related and environmental informabon from the TMI-2 cleanup.
ITEM ll.H.1: MAINTAIN SAFETY OF TMI-2 AND MINIMlZE ENVIRONMENTAL IMPACT DESCRIPTION This TMI Action Plan" item covered the efforts by NRC to monstor, review, and assess the safety l and environmental impact of the post-accident operation, cleanup, and possible recovery I operations at TMI-2 to ensure that: (1) reactor safety and reactor buhding integrity was maintained; (2) environmental impacts were minimized and radiation exposure to workers, the public, and the environment was within regulatory limits and was as low as reasonably achievable (ALARA); and (3) storage and/or disposal of radioactive wastes from cleanup operations were safe. The TMI Program Office (TMIPO) within NRR directed the NRC activities under this task.
NUREG-0698,'" Rev.1, was issued in February 1982 and provided an updated chronology of TMI-2 cleanup activity, major milestones, and accomplishments summarized as follows:
[
(1) In March 1981, the NRC issued NUREG-0683,* a Final Programmatic Environmental Impact Statement (PElS) related to the decontamination and disposal of radioactive wastes resulting from the accident.
(2) In conjunction with the issuance of the PElS, the NRC also issued a Policy Statement21' in April 1981 which stated that the cleanup should be expedited ;
consistent with maintaining public health and safety. 1 (3) in July 1981, a Memorandum of Understanding (Appendix A to NUREG-0698*) !
conceming the removal and disposition of radioactive solid wastes from the !
cleanup operations was signed by representatives of NRC and DOE.
l (4) Cleanup operations were implemented according to the plan. Decontamination of accident-generated water in the auxiliary and fuel handling buildings was completed by mid-1981. Decontamination of accident water located in the reactor building sump and reactor coolant system was initiated in September 1981. Visual examination of the top of the damaged reactor core was performed with the use of a remote miniature TV introduced through control rod drive housing.
This issue was identified in NUREG-088521o as one of NRC's highest safety priorities.
12/31/98 1.II.H-1 NUREG-0933
l 1
Revision 3 CONCLUSION The cleanup operation was implemented2" and the issue was programmatically RESOLVED with appropriate management resources and priorities assigned; no new requirements were established. In NUREG/CR-5382,"'8 it was concluded that consideration of a 20-year license renewal period did not affect the resolution.
ITEM ll.H.2: OBTAIN TECHNICAL DATA ON THE CONDITIONS INSIDE THE TMI-2 CONTAINMENT STRUCTURE DESCRIPTION Pertinent technical information was to be obtained on the conditions of the TMI-2 facility as cleanup operations proceeded. The information to be gathered and disseminated (item II.H.3) was I divided into two distinct categories: (1) data to be obtained prior to gaining access to the primary system; and (2) data to be obtained after access to the primary system. In the first category, information was to be obtained on: (1) instrumentation and electdcal equipment survivability under the accident conditions; (2) environmental conditions in the containment and auxiliary buildings; (3) fission-product release, transport, and deposition; (4) decontamination, dose reduction, and waste handling; and (5) debris in the containment building, in particular the containment sump.
After access to the primary system was obtained, the primary system pressure boundary was to i be characterized including the steam generators, pumps, and other mechanical and structural j components. Techniques were to be developed for a non-destructive assay of fuel distribution in j the primary system for assessing criticality control during examination and cleanup operations and l for fuel removal, packaging, shipment, and disposal. Detailed pre-access reactor and core damage assessments were to be made followed by carefulin situ and away-from-site fuel and reactor intemals examinations.
The societal risk from the operation of nuclear power plants would not be reduced by just obtaining, preserving, and disseminating information as outlined above. However, the potential for risk reduction due to proper use of increased knowledge obtained by studying the TMI-2 facility cannot be denied. The information that could be obtained through this item was to be used in the l
pursuance of other safety issues such as.
l A-45 Shutdown Decay Heat Removal Requirements l A-48 Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment II.B.5 Research on Phenomena Associated with Core Degradation on Fuel {
Melting l 11.B.7 Analysis of Hydrogen Control '
ll.B.8 Rulemaking Proceedings on Degraded Core Accidents ll.E.3.4 Attemate Decay Heat Removal Concepts Insights gained from the above TMI-2 information were assumed in a qualitative sense in the development of the potential risk reduction for the 6 issues outlined above. The total risk reduction estimated for the resolution of these 6 issues was 610,000 man-rem of public exposure and 9
12/31/98 1.II.H-2 NUREG-0933
Revision 3
' 650,000 man-rom of mW exposure; to include further potential risk reduction under item '
II.H.2 (and ll.H.3) would result in double-countmg. ,
At the time this issue was evaluated, it was assumed that the TMI-2 cleanup was about 40%
complete, about 60% of the $1.2 Billion licensee estimated cost remained to be expended, and about 10% of the licensee's costs was consumed in the preservation and recording of technical data. It was estimated that there was $72M of licensee funding yet to be expended on this effort.
Using the TMl Action Plan" cost and manpower estimates and extrapolating through FY-1985, it was determined that the NRC cost would be about $36M, of which, about 60% or $22M had not yet been expended. It was also assumed that a DOE commitment of approximately $22M had yet to be expended. This resulted in a total future cost of about $116M for the completion of items ll.H.2 and ll.H.3.
Table ll.H.2-1 shows the estimated risk reduchon, cost, and recommended pnonty for each of the above 6 issues. The total future costs estimated for all 6 issues was approximately $2 Billion. The i total future cost for completion of items ll.H.2 and ll.H.3, although large ($116M), was a reasonably small portion (~6%) of total future costs expected for the resolution of those safety issues that will utilize information obtained from the TMI-2 facility. If the cost associated with these items was compared only with the estimated total cost for resolving issues A-45 and A-48, the cost of the TMl information retrieval program would represent only about 15% of the cost of these two issues. Compared to items 11.B.5 and ll.B.8, the cost of the TMI information retrieval program represented less than 10% of the estimated cost for the completion and implementation of items II.H.2 and ll.H.3.
Table ll.H.2-1 issue Recommended Risk Reduction Total Cost Priority (Man-Rem) ($M)
A-45* High 4.7 x 105 500 A-48* High 5.2 x 105 208 II.B.5 High 2.2 x 105 1,300 11.B.7 (Subsumed in A-48) - -
II.B.8 (Subsumed in ll.B.5) - -
II.E.3.4 (Subsumed in A-45) - -
l TOTAL 1.2 X 10s 2,008
- Unreleased Draft Analyses i
CONCLUSION This issue addressed the collection (Item II.H.2) and dissemination (Item II.H.3) of information that was to be used in the completion of other specific safety issues and thus was not analyzed separately. However, examination of the recommended priority for those issues that depended 12/31/98 1.ll.H-3 NUREG-0933
i l
l Revision 3 in part on input from the TMI information to be obtained via this issue indicated that this issue supported other high priority issues. Thus, this issue was given a high priority (See Appendix C).
Core examinations indicated that a large flow of molten material (about 19 metric tons) relocated into the lower plenum after the accident had been in progress for about 225 minutes. All vessel steel, nozzle, and guide tube samples extracted from TMi-2 were tested and analyses of the potetial reactor vessel failure modes were conducted. The staff's findings were forwarded to the Colnrnission in SECY-93-119."
- Thus, this issue was RESOLVED with no new requirements.""
Cunsideration of a 20-year license renewal period would not affect this resolution.
ITEM ll.H 3: EVALUATE AND FEEDBACK INFORMATION OBTAINED FROM TMI-2 DESCRIPTION This TMl Action Plan" item involved the analysis of data obtained during the examination of systems inside the containment building at TMI-2, the subsequent decontamination and restoration of the facility, and the feedback of the information obtained into other appropriate regulatory programs. Item II.H.2 was devoted to the efforts necessary to acquire and record information during the cleanup of the TMI-2 facility.
CONCLUSION Since the acquisition of the TMI-2 data had to be accomplished before the data could be evaluated, no changes in requirements could be ascertained until those data were evaluated.
Therefore, items li.H.2 and ll.H.3 were inextricable and were combined and evaluated together under item II.H.2.
ITEM ll.H.4: DETERMINE IMPACT OF TMI ON SOClOECONOMIC AND REAL PROPERTY VALUES DESCRIPTION Studies were to be conducted on: (1) the effect of the TMI accident on the value of real property in the Harrisburg, Pennsylvania, area; and (2) the socioeconomic impact of the TMI accident on the region in south-central Pennsylvania which surrounds TMI. This item was initiated to increase the NRC knowledge in assessing levels of safety and, therefore, was considered a Licensing issue.
CONCLUSION j A Pennsylvania State University study3 '3 of the effects of the accident on property values in the vicinity of the TMI-2 site was accepted by the staff and published in March 1981. A study of the socioeconomic effects of the accident in the region surrounding the plants was performed by Mountain West Research incorporated. This report " was accepted by the staff and published in July 1982. Thus, this Licensing issue was resolved. l l
12/31/98 1.ll.H-4 NUREG-0933 l
Rsvision 3 O REFERENCES b 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMl-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
198. NUREG-0698, "NRC Plans for Cleanup Operations at Three Mile Island Unit 2," U.S.
Nuclear Regulatory Commission, July 1950.
199. NUREG-0683, " Final Programmatic Environmental impact Statement Related to Decontamination and Disposal of Radioactive Wastes Resulting from the March 28,1979 Accident at Three Mile Island Nuclear Station, Unit 2," U.S. Nuclear Regulatory Commission, March 1981.
210. NUREG-0885,"U.S. Nuclear Regulatory Commission Policy and Planning Guidance," U.S.
Nuclear Regulatory Comnmission, (Issue 1) January 1982, (issue 2) January 1983, (Issue
- 3) January 1984, (issue 4) February 1985, (issue 5) February 1986, (Issue 6) September 1987.
211. Federal Reaister Notice 46 FR 764, "NRC Policy Statement on Cleanup of the Three Mile Island Plant," May 1,1981.
313. NUREG/CR-2063, " Effects of the Accident of Three Mile Island on Property Values and Sales," U.S. Nuclear Regulatory Commission, March 1981.
314. NUREG/CR-2749, " Socioeconomic impacts of Nuclear Generating Stations - Three Mile Island Case Study," U.S. Nuclear Regulatory Commission, (Vol.12) July 1982.
377. Memorandum for W. Minners from B. Snyder, " Schedule for Resolving and Completing Generic issues," December 16,1982.
1539. SECY-93-119, "TMI-2 Vessel Investigation Project," May 5,1993. i 1540. Memorandum forJ. Taylor from E. Beckjord, " Closure of Generic issue ll.H.2, 'Obtain Data on Conditions inside TMI-2 Containment,'" February 9,1994.
1563. NUREG/CR-5382, " Screening of Generic Safety issues for License Renewal l Considerations," U.S. Nuclear Regulatory Commission, December 1991.
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12/31/98 1.II.H-5 NUREG-0933
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O l
O 1
I l
1 l
1 I
]
l l
9
r l'
i' Rsvision 1 i
l TASK ll.J: GENERAL IMPLICATIONS OFTMl FOR DESIGN AND CONSTRUCTION ACTIVITIES
, TASK ll.J.1: VENDOR INSPECTION PROGRAM -
l The objective of this task was to improve vendor-supplied components and services through a modified and more effective vendor inspecbon program.
l ITEM ll.J.1.1: ESTABLISH A PRIORITY SYSTEM FOR CONDUCTING VENDOR INSPECTIONS DESCRIPTION This TMI Action Plan" item called for the NRC to develop an integrated information system to establish priorities for selecting vendors for inspechon in order to permit optimum utilization of available resources. Prionties were to be based on the relatwo safety significance of products and services provided by the vendors. The information necessary to establish the priorities was to be collected and integrated from LERs, deficiency reports from holders of construction permits and non-licensees, and other relevant information. This item addressed improvement in the NRC
! capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
CONCLUSION A contract study, " Development of the Automated Vendor Selechon System," was completed by Gasser Associates, Inc. on June 30,1980, and was reviewed by OIE. Changes in the vendor selection and inspection procedures that were considered appropriate were incorporated into the OIE Manual, Chapter 2700, in July 1981. Thus, all required action on this item was completed 23s,2a.37tes and the issue was resolved with changes in NRC procedures that address vendor selection and inspechon.
ITEM ll.J.1.2: MODIFY EXISTING VENDOR INSPECTION PROGRAM i DESCRIPTION l
This TMl Action Plan" item called for the NRC to improve existing vendor inspection procedures by including more routine technical assessments of products, by expanding the scope to reflect operational and construction feedback experience, and by placing greater emphasis on design control and the use of independent measurements. Full implementation of the expanded scope of this program required an increase in vendor inspection staff. This item addressed improvement in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
O l
12/31/98 1.ll.J.1-1 NUREG-0933
Revision 1 CONCLUSION Chapter 2700 of the ole Manual, which described the overall licensee contractor and vendor inspection program, was revised to incorporate the fundamental changes defined by this item.2st297 W th respect to staffing, additional positions for the vendor inspection program were authorized and, by November 1983,26 people were performing vendor inspection functions. The program changes required by this item were incorporated into the routine ongoing vendor inspection program. Detailed inspection procedures covering these program activities were prepared as the needs of the program were identified. Thus, all required action on this item was completed 297.srs and the issue was resolved with changes to NRC procedures that address licensee vendor inspection programs.
ITEM ll.J.1.3: INCREASE REGULATORY CONTROL OVER PRESENT NON-LICENSEES ,
I' DESCRIPTION This TMI Action Plan" item required the NRC to study the need to extend its licensing authority !
over vendors who supply components and services to licensees. Nuclear steam system suppliers, )
architect / engineers, constructors, and designated vendors were to be included in the study. Upon completion of the study, the staff was to present a paper to the Commission for a decision on the subject. This item addressed improvement in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
CONCLUSION As part of the resolution of item II.J.4.1, OIE submitted to RES recommended changes to 10 CFR l 21 that would revise deficiency reporting requirements for NSSS vendors, A/E firms, and others. l These revised deficiency reporting requirements would provide increased information on l component failures that affect safety, so that prompt and effective corrective action could be ,
taken. ole stated 23 s that further extension of NRC authority over non-licensees with licensing I requirements was not warranted and would not be cost-effective. in light of the proposed rule change, all required action was completed 78 and the issue was resolved.
ITEM ll.J,1.4: ASSIGN RESIDENT INSPECTORS TO REACTOR VENDORS AND ARCHITECT ENGINEERS DESCRIPTION This TMI Action Plan" item required the NRC to evaluate the desirability of assigning resident inspectors to NSSS vendors and A/Es. The staff was, to prepare a Commission Paper describing a proposed trial program to be applied to selected NSSS vendors and A/Es. This item addressed improvement in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
O 12/31/98 1.II.J.1-2 NUREG-0933
Ravision 1 i
CONCLUSION L
The proposal to assign resident inspectors to NSSS vendors and A/Es as a part of the vendor inspection program was reviewed by the staff who concluded 23s.2se that such a program should not be initiated it was further recommended37' that the item be deleted for the following reasons 2a (1) more effective utilization of existing vendorinspection resources could be obtained by retaining inspectors in the regional offices; (2) the absence of new orders resulted in significant changes in NSSS and A/E. work activity, in that more sub-contracting to numerous small firms was occurring; (3) to provide inspection coverage of the activities required greater mobility and flexibility from the vendor inspection staff; and (4) the trial program would require resources that were not available. Based on these recommendations, the issue was resolved.
REFERENCES
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1990.
235. Memorandum for H. Denton from R. DeYoung,"TMI Action Plan Items Still Pending," June 10,1982.
248. Memorandum for W. Dircks from R. DeYoung, "TMI Action Plan - Completed Items,"
December 28,1981.
259. Memorandum for J. Sniezek from J. Taylor, "TMl Action Plan item II.J.1.2, Modification of Vendor Inspection Program," October 13,1982.
268. Memorandum for W. Dircks from V. Stello, " Assignment of Resident inspect?rs to Nuclear Steam System Suppliers and Architect-Engineers," September 141981.
297. Memorandum for W. Dircks from R. DeYoung, "TMI Action Plan - Completed item,"
October 29,1982.
379. Memorandum for H. Denton from R. DeYoung, " Draft Report on the Prioritization of Non-NRR TMI Action Plan items," January 24,1983.
406. Memorandum for W. Dircks from R. DeYoung, "TMl Action Plan - Status Report," March 14,1982.
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I 12/31/98 1.II.J.1-3 NUREG-0933
Rsvision 1 TASK II.J.2: CONSTRUCTION INSPECTION PROGRAM The objective of this task was to provide greater assurance that nuclear plants are properly constructed by improving construchon inspechon programs.
ITEM ll.J.2.1: REORIENT CONSTRUCTION INSPECTION PROGRAM DESCRIPTION This TMl Action Plan" item called for OIE to change its reactor construction inspection program and its inspechon Manual to require increased observation of work activities, more attention to the involvement of licensees in construction activities, independent verification that as-built conditions met design requirements, and followup of reported incident information, as applicable, from i operating reactors. This item addressed the NRC capability to make independent assessments !
of safety and, therefore, was considered a Licensing issue.
)
i CONCLUSION Chapter 2512 of the inspechon Manual was revised on August 1,1980, as part of the ole program to incorporate increased observation of work activities and to increase inspection of licensees' l O involvement in the overall construction of plants. In addition, program changes to ensure earlier and continuing inspection of construchon QA activities were made. A trial program involving team inspections was also completed. Thus, this issue was resolved with changes in the NRC 1
l procedures that address construction inspechon 23s,m,37tes ll.J.2.2: INCREASE EMPHASIS ON INDEPENDENT MEASUREMENT IN CONSTRUCTION INSPECTION PROGRAM DESCRIPTION l This TMl Action Plan" item called for ole to evaluate trial programs involving independent measurements (non-destructive examination) at construebon sites. NRC was to buy a van to be fitted with equipment to conduct ultrasonic, liquid penetrant, and magnetic particle non-destructive examinations. If the evaluations were successfully made from the equipment-fitted van, additional vans were to be purchased for use at each Regional Office. In addition, a contract was awarded to the Franklin Research Center to provide services involving independent assessment (destructive testing) of material samples. Data from these assessments were to supplement the testing to further verify conformance with licensee commitments, specifications and/or codes and standards requirements. Five uniquely qualified inspectors were to be assigned full-time to each van to ensure maximum use of the vans. This item addressed improvement in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
\
12/31/98 1.II.J.2-1 NUREG-0933
Revision 1 CONCLUSION A contractor for destructive testing was hired and tests were performed on an ongoing basis. An NRC mobile van was purchased, equipped, and staffed with contractor assistance. The original plan called 2" for the staff to evaluate a trial program involving independent measurements at construction sites and then, based upon the results of the trial program, equip each region with the capability and equipment necessary to conductindependent measurements on a routine basis.
The trial program was a success; however, based on budgetary constraints, a cutback in the effort was necessitated. ole recommended a modified scope of the item so that the effort was limited to purchasing one van which would be available to all five regions. Personnel to utilize van equipment were supplied by an NRC contractor. This eliminated the need to hire additional full-time personnel and to provide a training program necessary to maintain personnel competency in NDE disciplines.
This issue was resolved when the scope of the action plan was revised and the program of independent measurements was incorporated into routine NRC operations. 7' Followup was to be performed via routine programmatic action, and further expansion was to be based on continuing ole appraisal of the program's effectiveness.
ITEM ll.J.2.3: ASSIGN RESIDENT INSPECTORS TO ALL CONSTRUCTION SITES DESCRIPTION This TMI Action Plan" item called for ole to expand the resident inspector program to include one inspector at each power plant construction site. Previous experience had shown the need for inspection at all stages of construction. This conclusion contradicted earlier criteria that delayed the assignment of residentinspectors to a plant site until 50% of the construction was completed.
Schedules and resources for assigning resident inspectors to construction sites were to t,e developed in connection with routine agency budgetary processes. This item addressed improvement in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
CONCLUSION OIE assigned resident inspectors to all active construction sites that were greater than 15%
complete.2" In November 1983, there were 23 resident inspectors at various construction sites.
This item was developed as part of the routine program for NRC operators and was resolved when it was decided that future specific allocation of resources in this inspection program would be reevaluated as part of the annual budget process.878 REFERENCES ,
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
235. Memorandum for H. Denton from R. DeYoung, "TMI Action Plan items Still Pending," June 10,1982. t O'
12/31/98 1.II.J.2-2 NUREG-0933 l _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Rsvision 1 239. Memorandum for W. Dircks from V. Stello, "TMI Action Plan - Status Report," December 19,1980.
,l 379. Memorandum for H. Denton from R. DeYoung, " Draft Report on the Prioritization of Non-NRR TMl Action Plan items," January 24,1983.
406. Memorandum for W. Dircks from R. DeYoung, "TMI Action Plan - Status Report," March 14,1982.
5 O
12/31/98 1.ll.J.2-3 NUREG-0933
Rsvision 1 L
TASK II.J.3: MANAGEMENT FOR DESIGN AND CONSTRUCTION The objective of this task was to improve the qualification of licensees for operating nuclear power l plants by requiring greater oversight of design, construction, and modification activities. l ITEM ll.J.3.1: ORGANIZATION AND STAFFING TO OVERSEE DESIGN AND CONSTRUCTION DESCRIPTION The purpose of this TMl Action Plan" item was to require " license applicants and licensees to improve the oversight of design, construction, and modification activities so that they will gain the critical expertise necessary for the safe operation of the plant."
CONCLUSION The criteria and regulatory guidelines for this issue were addressed and developed by DHFS/NRR as a part of item 1.B.1.1. Therefore, this issue was covered in item I.B.1.1.
ITEM ll.J.3.2: ISSUE REGULATORY GUIDE O
V DESCRIPTION The purpose of this TMl Action Plan" item was to issue a Regulatory Guide to codify the criteria relating to organization and staffing to oversee design and construction (Item II.J.3.1). I CONCLUSION i
inis item required the utilization of criteria developed from item II.J.3.1. Therefore, this item was evaluated together with item II.J.3.1 under item 1.B.1.1.
REFERENCE
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
O 12/31/98 1.ll.J.3-1 NUREG-0933
l Rsvision 3 TASK ll.J.4: REVISE DEFICIENCY REPORTING REQUIREMENTS
. The objective of this taskwas to clarify deficiency report requirements to obtain uniform reporting and eadieridentification and conoction of problems.
ITEM ll.J.4.1: REVISE DEFICIENCY REPORTING REQUIREMENTS DESCRIPTION This TMI Action Plan" item called for the NRC to revise, as necessary, the event-reporting requirements of 10 CFR 21 to assure that all reportable dams are reported promptly and that the information submitted is complete. Improvements were to be implemented by rule changes, as appropriate, and coordinated with those made under TMI Action Plan item 1.E.6. The reports received as a result of these rule changes were to provide increased information on component failures that affect safety so that prompt and effective corrective action could be taken. The information was also to be used as input to an augmented role of the NRC's vendor and construction inspection program.
CONCLUSION i This issue was originally classified as nearty-resolved, based on changes to 10 CFR 21 and 10
- CFR 50.55(e) proposed by OIE,as,a2 and was later RESOLVED with new requirements when amendments to 10 CFR 21 and 10 CFR 50.55(e) were issued.'" The staff's changes were presented to the Commission in SECY-91-150.'" In an RES evaluation,'" it was concluded that consideration of a 20-yearlicense renewal period did not affact the resolution.
REFERENCES
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev.1) August 1980.
I 291. Memorandum for E. Jordan, et al., from R. Bemero, " Proposed Rule Review Request - 10 CFR Part 21, ' Reporting of Defects and Non-Compliance,'" February 3,1983.
1396. Federal Reaister Notice 56 FR 36081, "10 CFR Parts 21 and 50, Criteria and Procedures for the Reporting of Defects and Conditions of Construction Permits," July 31,1991.
1397. SECY-91-150, " Proposed Amendments to 10 CFR Part 21, ' Reporting of Defects and Noncompliance' and 10 CFR 50.55(e), ' Conditions of Construction Permits,'" May 22, 1991.
1564. Memorandum forW. Russell from E. Beckjord," License Renewalimplications of Generic Safety issues (GSis) Prioritized and/or Resolved Between October 1990 and March 1994,"
May 5,1994.
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E_ i
Ravision 3 O
V TASK lli.D.2: PUBLIC RADIATION PROTECTION IMPROVEMENT The objective of this task was to improve public radiation protection in the event of a nuclear power plant accident by improving: (1) radioactive effluent monitoring; (2) the dose analysis for accidental releases of radioiodine, tritium, and carbon-14; (3) the control of radioactivity released into the liquid pathway; (4) the measurement of offsite radiation doses; and (5) the ability to rapidly determine offsite doses from radioactivity release by meteorological and hydrological -
measurements so that population-protechon decisions can be made appropriately.
I ITEM lll.D.2.1: RADIOLOGICAL MONITORING OF EFFLUENTS The three parts of this item were combined and evaluated together.
DESCRIPTION l distorical Backaround This TMI Action Plan ** item required development and implementation of acceptance criteria for monitors used to evaluate effluent releases under accident and post-accident conditions. Criteria were to be developed for pathways to be monitored (stack, plant vent, steam dump vents) as well as for monitoring instrumentation. To meet the new criteria, licensees would have to develop, procure, and install monitoring systems that were, at the time of this evaluation, beyond the state-of-the-art. This was seen to encompass the requirements in NUREG-0578,57 Recommendation 2.1.8-b, and Appendix 2 to NUREG-0654.224 Liquid effluents were not envisioned as posing a major release pathway because licensees typically had installed, or were installing,- adequate storage capacity to prevent discharges.
Consequently, existing liquid effluent monitoring systems were considered adequate.
Safety Sianificance This issue had no impact on core-melt accident frequency.
Possible Solution The envisioned monitoring system would provide automatic on-line analysis of airbome effluents including isotopic analyses of particulate, radioiodine, and gas samples. To prevent saturation of i; detectors, an automatic sample cartridge changeout feature would be included. The system would include microprocessor control and real-time readouts and would be located in a low post-accident background area. The sampling system would be designed to provide a representative sample under anticipated accident release conditions.
A PWR steam-dump sampling and monitoring system would be provided for PWR safety relief and
' vent valves. Such a system might consist of a noble gas monitor and a radioiodine sampling and monitoring system. The features of such a system would be similar to the above-described 12/31/98 1.Ill.D.2-1 NUREG-0933
Revision 3 airbome effluent monitorwith two notable differences: (1) the system would be required to function in a very high humidity (steam-air mixture) environment; and (2) operation would only be required i during actual steam venting. Because such venting is usually of a short-term or intermittent duration, the monitoring system activation could be keyed to the opening of the vents.
PRIORITY DETERMINATION Assumptions it was assumed that improved radiological monitoring of airbome effluent would result in a reduction of public risk.
Frecuency/Conseauence Estimate The magnitude of public risk reduction attributable to improved radiological monitoring of airborne effluents was not certain, but it was estimated by PNL" to range from zero to 1%, based on the following logic.
Existing radiological monitoring requirements, as contained in NUREG-0737," require real-time noble gas monitoring with sampling and laboratory analysis capabilities for radiciodines and particulates. Design basis conditions defined in NUREG-0737" (100 pCi/cc radiciodines and particulates,30-minute sample time) indicated that sample collection devices would pose special handling and analysis problems due to very high radioactivity buildup. Consequently, licensees typically provided attemate sample collection and analysis procedures. Execution of those ,
procedures was estimated to require between 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. During this time, radiciodine and particulate releases would be estimated based on computer-modeled interpretation of noble gas monitor readings, or on previous post-accident containment atmosphere analysis results, if such results were available. Public protective action recommendations would be made based on modeled estimates rather than actual effluent data. It was assun.ed that these recommendations would err on the conservative side (e.g., evacuate when not really required), due to the q conservatism built into the modeled source terms for radiciodine and particulate releases.
Requiring licensees to have more sophisticated airbome effluent monitors would reduce the time required for obtaining actual radioiodine and particulate release data to 15 minutes, and essentially eliminate reliance on conservative theoretical release models extrapolated from noble gas monitor readings. As projected by the possible solution, real-time isotopic monitoring would save nearly two hours in arriving at realistic protective action recommendations based on actual releases.
Under these circumstances, the public risk reduction would be directiy attributed to the decrease in public radiation exposure which would result from a more rapid assessment of the radioactive releases (about a 2-hour savings in analysis time). There may also be a public risk reductlon due to non-evacuation. This could result from better knowledge of the isotopic releases eliminating the need for evacuation (presumed to exi t if release knowledge was based only on noble gas monitor data). Non-evacuation would result in less evacuation-related risks (e.g., traffic accidents), the avoidance of which may outweigh the radiation exposure received. However, it was assumed that the public risk reduction would result primarily from the first effect (decrease in exposure due to more rapid assessment).
O 12/31/98 1.lli.D.2-2 NUREG-0933
Revision 3 l While protective actions can be recommended based on effluent releases in progress, the probability for a core-melt scenario was such that actions would be recommended based on anticipated releases, prior to the actual release themselves. Under this assumption, monitoring effluent releases would have little or no impact on public risk and would be mainly for confirmation and quantification. This possible solution would not impact core-melt accident frequency.
I At the time of this evaluation, there were 134 plants affected by the issue: 71 operating (47 PWRs and 24 BWRs) and 63 planned (43 PWRs and 20 BWRs). It was assumed that the average remaining plant life was 27.4 years for the 44 BWRs, and 28.8 years for the 90 PWRs. The dose factors for PWR Release Categories 1 through 7 and BWR Release Categories 1 through 4 were j assumed to be affected by the possible solution. From NUREG/CR-2800, a 1% decrease in the dose factors resulted in an estimated total public risk reduction of 8,500 man-rem for all plants.
Assuming a decrease in the dose factors of 0.5% for this issue, the estimated public risk reduction was 4,250 man-rem.
Cost Estimate l
Industry Cost: The industry cost for equipment development, installation, support facilities, and "
construction was estimated to be $600,000/ plant. Development of procedures, software, and calibration for the equipment was estimated to require 16 man-weeks of effort, with an additional 4 man-weeks for the initial training of all licensee operators and health physics personnel. This was estimated to add $45,400/ plant to the implementation cost. Based on an estimated cost of
$645,000/ plant for labor and equipment, the industry cost for implementing the possible solution was (134 plants)($645,000/ plant) or $86.5M.
Ics' The recurring industry operation and maintenance costs were estimated at 2 man-weeks / plant-year for retrainin0.1 man-week / plant-year for calibration, and a reduction of 1 man-week / plant-year (reduced laboratory analyses due to a fully automated system) for a net increase of 2 man-weeks / plant-year, or an increased cost of $4,540/ plant-year. As a result, industry costs for labor and material associated with operation and maintenance of the possible solution were estimated to be $17.2M.
Thus, the total industry cost associated with this issue was $(86.5 + 17.2)M or $103.7M.
NRC Cost: The NRC cost was assumed to be limited to implementation co.sts for development and plantinstallation. Since it was assumed that the new radiological monitoring systems would require no periodic inspection effort beyond that required for current systems, no additional N RC operation j cost was envisioned. The NRC development cost included 1.5 man-years and $200,000 for research, criteria development, and engineering development, for a total cost of $350,000. N RC administrat've and technical effort associated with the review and approval of licensee submittals was estimated at 0.3 man-week / plant for a total cost of $91,000 for all plants. Therefore, the total l NRC cost associated with this issue was $441,000.
i Total Cost: The total industry and NRC cost associated with the possible solution was $(103.7 + j 0.441)M or $104.1M. ;
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Rsvision 3 1
Value/ impact Assessment Based on an estimated public risk reduction of 4,250 man-rem and a cost of $104.1M for a !
possible solution, the value/ impact score was given by:
S = 4.250 man-rem
$104.1M <
1 i
= 41 man-rem /$M <
Other Considerations itwas anticipated thatimprovement of radiological monitoring of airbome effluents would have no significant impact on occupational risk. The dose required to install equipment would probably not exceed 0.5 man-rem, which was negligible compared to the typical 600 man-rem / year required to operate a plant. Minor man-rem savings might occur under accident conditions due to better direction of field survey teams; however, such savings would be negligible compared to the 19,900 man-rem total associated with response and cleanup following an accident.
Based on an estimated occupationaldose of 0.5 man-rem / plant forimplementation of the possible solution in 71 operating plants, the total risk increase was 36 man-rem for all plants. Inclusion of this factor into the above calculation would reduce the value/ impact score.
There was no accident avoidance cost for the resolution of this issue because improved radiological effluent monitoring systems would have no impact on accident frequency or cleanup and refurbishing costs.
CONCLUSION Based on the risk reduction potential and value/ impact score, the issue was given a LOW priority ranking (see Appendix C) in November 1983. In NUREG/CR-5382,"$ it was concluded that consideration of a 20-yearlicense renewal period could change the ranking of the issue to medium priority. Further prioritization, using the conversion factor of $2,000/ man-rem approved'888 by the Commission in September 1985, resulted in an impact /value ratio (R) of $24,390/ man-rem which did not change the priority ranking.
ITEM lli.D.2.1(1): EVALUATE THE FEASIBILITY AND PERFORM A VALUE-lMPACT ANALYSIS OF MODIFYING EFFLUENT-MONITORING DESIGN CRITERIA This item was evaluated in item Ill.D.2.1 above and was given a LOW priority ranking.
ITEM lil.D.2.1(2): STUDY THE FEASIBILITY OF REQUIRING THE DEVELOPMENT OF EFFECTIVE MEANS FOR MONITORING AND SAMPLING NOBLE GASES AND RADIOlODINE RELEASED TO THE ATMOSPHERE This item was evaluated in item Ill.D.2.1 above and was given a LOW priority ranking.
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Ravision 3 l
ITEM lli.D.2.1(3h REVISE REGULATORY GUIDES This item was evaluated in item lli.D.2.1 above and was given a LOW priority ranking.
ITEM lli.D.2.2: RADIOlODINE. CARBON-14. AND TRITIUM PATHWAY DOSE ANALYSIS The four parts of this item were combined and evaluated together.
DESCRIPTION Historical Backaround This TMl Action Plan" item addressed the issue of further research for improving the understanding of radioiodine partitioning in nuclear power reactors, and the environmental behavior of radioiodine, carbon-14, and tritium, following an accident and during normal operation.
lodine isotopes are considered to be major contributors to the occupational and public dose during a LOCA, along with noble gases and fission products. A study in these areas was documented 2
in NUREG-077212with the following majorconclusions: (1) uncertaintics in predicting atmospheric release source terms were very large (at least a factor of 10); (2) source terms for certain accident sequences may have been overestimated in past studies, e.g., WASH-1400; and (3) cesium iodide should be the predominant chemical form of iodine under severe accident conditions.
Safety Sionificance The above conclusions indicated that the methodology and assumptions used for evaluating radioiodine release could result in unrealistic estimates (e.g., Regulatory Guides 1.3243 and 1.42 u),
Also indicated was that more research in aerosol behavior and fission product chemistry was needed in order to improve and support the calculation methodology concemed with radioiodine partitioning, fission product behavior, etc.
Possible Solution it was assumed that further study would improve the understanding of this issue and result in more realistic assumptions and methods for evaluating source terms, releases, and environmental behavior of radioiodine, carbon-14, and tritium following an accident. This research would not affect accident frequencies at nuclear power plants. However, it was assumed that the results of these studies would be used to revise the SRP" and Regulatory Guides.
It was then assumed that the Regulatory Guide revhions could result in reducing the size of existing emergency planning zones (EPZs) from a 10-mile radius to a 2-mile radius. This assumption was based upon a reduction of source terms in a core-melt accident by a factor of 10.
This would result in reducing dose concentration at a particular distance from the nuclear reactor by a factor of 10 also. Assuming neutral weather conditions with a 30-meter-high plume, the offsite dose predicted at 2 miles from the accident scene, using the reduced source term assumption, would be the same as that predicted at 10 miles from the reactor.
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l l
Rsvision 3 '
CONCLUSION The study of radioiodine, carbon 14, and tritium behavior at TMI-2 called for in Item Ill.D.2.2(1) was completed in June 1981 and documented in NUREG-0771'55 and NUREG-0772.212 Items Ill.D.2.2(2), (3), and (4) called for a series of studies and evaluations of various radionuclide pathways and models followed, if necessary, by revisions to several SRP Sections and Regulatory Guides. As part of the staff's task to prepare and publish a manual (Offsite Dose Calculation Manual) to be used by the NRC and industry to estimate individual and population doses during normal and accident conditions, items Ill.D.2.2(2), (3), and (4) were assessed. This Offsite Dose Calculation Manual was prepared underltem ill.D.2.5 and fully described each of the theoretical models used to predict radionuclide transport.'** Thus, Items Ill.D.2.2(2), (3), and (4) were covered under item lli.D.2.5.
ITEM lli.D.2.2(1): PERFORM STUDY OF RADICIODINE. CARBON-14. ANDTRITIUM BEHAVIOR This item was evaluated in item Ill.D.2.2 above and was RESOLVED with no new requirements.
ITEM lli.D.2.2(2): EVALUATE DATA COLLECTED AT QUAD CITIES This item was evaluated in item Hi.D.2.2 above and was determined to be covered in item lli.D.2.5.
ITEM lli.D.2.2.(3): DETERMINE THE DIS'iRIBUTION OF THE CHEMICAL SPECIES OF RADIOIODINE IN AIR-WATER-STEAM MIXTURES This item was evaluated in Item lli.D.2.2 above and was determined to be covered in item Ill.D.2.5.
ITEM lli.D.2.2.(4): REVISE SRP AND REGULATORY GUIDES This item was evaluated in item Ill.D.2.2 above and was determined to be covered in Item Ill.D.2.5.
i ITEM lli.D.2.3: LIQUID PATHWAY RADIOLOGICAL CONTROL The four parts of this item were combined and evaluated together.
DESCRIPTION This TMl Action Planda tem was concemed with improving public radiation protection in the event of a nuclear power plant accident by improving the control of radicactivity released into the liquid pathway. This control could be accomplished by the application of various interdictive measures
, at the source of the release and/or along the liquid pathway. Techniques were developed and l L were being used to evaluate the liquid pathway effects of an accident for each reactor site. Sites that might require interdictive measures related to liquid pathway releases were to be determined.
Interdictive measures were to be assessed as to their effectiveness in improving public radiation protection.
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e Rsvision 3 CONCLUSION A liquid pathway analysis for Zion was completed by DE/NRR in 1980.3e' In addition, a liquid pathway analysis was performed forindian Point. Both analyses were utilized in NUREG-0850.*"
A simplified analysis for liquid pathway studies (NUREG-1054)* was published in August 1984 and Section 7.1.1 of the Environmental Standard Review Plan (ESRP)* was drafted with no new requirements for licensees or applicants.** ESRP Sechon 7.1.1 was finally published as NUREG 1165* in November 1985. Thus, this item was RESOLVED and no new requirements were established.7" ITEM lli.D.2.3(1): DEVELOP PROCEDURES TO DISCRIMINATE BETWEEN SITES / PLANTS This item was evaluated in item lli.D.2.3 above and was RESOLVED with no new requirements.7" ITEM lli.D.2.3(2): DISCRIMINATE BETWEEN SITES AND PLANTS THAT REQUIRE CONSIDERATION OF LIQU!D PATHWAY INTERDICTION TECHNIQUES This item was evaluated in item ill.D.2.3 above and was RESOLVED with no new requirements.7" ITEM lli.D.2.3(3): ESTABLISH FEASIBLE METHOD OF PATHWAY INTERDICTION This item was evaluated in item ill.D.2.3 above and was RESOLVED with no new requirements.7" ITEM lli.D.2.3(4): PREPARE A
SUMMARY
ASSESSMENT This item was evaluated in item lli.D.2.3 above and was RESOLVED with no new requirements.7" ITEM lil.D.2.4: OFFSITE DOSE MEASUREMENTS ITEM lli.D.2.4(1): STUDY FEASIBILITY OF ENVIRONMENTAL MONITORS DESCRIPTION This TMI Action Plan" item called for the staff to study the feasibility of environmental monitors capable of measuring real-time rates of exposuresto noble gases and radioiodines. Monitors or samplers capable r1 measuring respirable concentrations of radionuclides and particulates were also considered. '(his activity supported proposed revisions to Regulatory Guide 1.9755 (see item II.F.3).
CONCLUSION The establishment of guidance in Regulatory Guide 1.9755for fixed monitors to detect unidentified releases was postponed pending the outcome of a feasibility study which was completed in April T 1982.* Using this study as a basis, the staff concluded that environmental monitors of this nature 12/31/98 1.lli.D.2-7 NUREG-0933
Rsvision 3 were not practical and that proposed requirements for these monitors should be dropped from consideration.'88 Thus, all required action on this item was completedss2 and the issue was RESOLVED with no new requirements.
ITEM lil.D.2.4(2k PLACE 50 TLDs AROUND 'ACH SITE .
DESCRIPTION This TMI Action Plan" item called for OIE to place 50 TLDs around each site in coordination with states and utilities. During normal operation, OiE quarterly reports from these dosimeters were to be provided to NRC, state, and federal organizations. In the event of an accident, the dosimeters could then be read at a frequency appropriate to the needs of the situation.
The specific objectives of this program were to: (1) establish pre-operational, historical, baseline radiation dose levels, whenever possible, for each monitored facility; (2) provide ongoing radiation dosimetry data during routine operations; (3) provide post-accident radiation dosimetry to aid in assessment of population exposures and radiologicalimpact; (4) allow for independent verification of the adequacy of NRC licensees' environmental radiation monitoring programs; (5) provide uniform treatment of dosimeters with respect to handling, shipping, calibrating, reading, and data processing for all monitored facilities in the U.S.; and (6) provide uniform, consistent environmental radiation monitoring data for use by the Congress, federal and state agencies, monitored facilities, and the public.
This item addressed improvements in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing issue.
CONCLUSION OIE completed installation of TLDs at all operating reactors in August 1980 in accordance with the TMI Action Plan schedule. A Direct Radiation Monitoring Network was established and a program for routine reporting began. The completion of these activities was described in an OIE memorandum.23e With the establishment of the NRC TLD Direct Radiation Monitoring Network, the installation of TLDs at all operating reactor sites, and the routine reporting of the TLD measurements, all work required by this item was completed.23e.37s Thus, this Licensing issue was l resolved.
ITEM lli.D.2.5: OFFSITE DOSE CALCULATION MANUAL DESCRIPTION Historical Backaround This TMI Action Plan" item called for NRR to prepare a manual to be used by the NRC and plant personnel to estimate the maximum individual doses and population doses during an accident.
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Ravision 3 l
Safety Sianificance
- l. I l
This issue did not affect core-melt frequency or the amount of radioactivity released. Instead, it was intended to reduce the consequences of a major release by assuring that licensees have a l
rapid and sufficiently accurate method of estimating dose, and that communication between ;
licensees and the NRC be expedited by having a common standard calculation method for both.
Possible Solution
[ The proposed manual was expected to include formulations with which to combine source term i
and meteorological measuroments. This would determine offsite dose rates in a manner that would be standard among all parties making decisions on public protection and emergency response. Appendix 2 to NUREG-0654 224 established criteria for automated assessment of j radiation doses in the event of an accident.
PRIORITY DETERMINATION Frecuency Estimate Since the proposed solution to the issue did not affect core-melt accident frequency, the i frequencies for the various release categories given for Oconee-3 and Grand Gulf-1 were used unchanged in the value/ impact calculation.
I Consecuence Estimate t
8d l In an assessment of this issue, PNL expertsjudged that a 1% reduction in public dose (man-rem)
! might be expected as a result of having the offsite dose calculation manual available. It was estimated that the changes in consequences would be much less (0.01% to 0.1%) Since all sequences would be affected and the risk from both PWRs and BWRs was about 210 to 250
- man-rem /RY, the risk reduction was estimated to be 0.02 to 0.2 man-rem /RY.
At the time of the evaluation of this issue in November 1983, there were 43 PWRs and 27 BWRs operating with cumulative experience of 350 RY and 260 RY, respectively. Considering the 36 PWRs and 21 BWRs that were under construction and assuming a plant life of 40 years, there were 2,810 PWR-years and 1,660 BWR-years in the future, for a total of 4,470 RY. Therefore, the total risk reduction associated with this issue was (0.2)(4,470) man-rem or 894 man-rem.
Cost Estimate Industry Cost For licensees,4 man-weeks of training for implementation were assumed, since operators were being retrained periodically and this retraining could include dose calculation methods. This different method would not incur additional recurring costs. Thus, the total industry cost was estimated to be $7,700/ plant or $0.98M for 127 plants.
NRC Cost: The NRC had already completed work on development of a portable computerized system for dose calculations to be used by the NRC Regional Offices. This was part of the program for NUREG-0654.22* This program was developed to the point of field trials for the computerized system. Based on the development costs, an additional $125,000 to develop this package into a manual form for use by utilities was assumed. It was estimated that NRC site 12/31/98 1.lli.D.2-9 NUREG-0933
{
Revision 3 i
representatives could spend a minimal amount of time (~2 days) to evaluate initial utility performance with the package. This was estimated to be $600/ plant. Thus, the total NRC cost was approximately $200,000 for all plants.
l Total Cost: The total industry and NRC cost associated with the possible solution was $(0.98 +
0.2)M or approximately $1.2M.
Value/ impact Assessment Based on an estimated public risk reduction of 894 man-rem and a cost of $1.2M for a possible solution, the value/ impact score was given by: !
S = 894 man-rem
$1.2M
= 758 man-rem /$M CONCLUSION Based on the above value/ impact score, the issue would have had a medium priority ranking (see Appendix C). However, prior to approval of the prioritization evaluation in November 1983, the Offsite Dose Calculation Manual was published as NUREG/CR-3332.5SS Thus, the issue was RESOLVED and no new requirements were issued.ssa ITEM lli.D.2.6: INDEPENDENT RADIOLOGICAL MEASUREMENTS Ol 1 l
l DESCRIPTION This TMI Action Plan" item dealt with independent radiological measurements, i.e., means of collecting data independent of licensees' programs. An OIE task force developed a plan and requiremen's for upgrading the capability of Regional Offices to perform independent radiological measurements during routine inspections and emergency response operations. The objective of the upgrade was to achieve consistent capability among the Regional Offices, including standardization in major equipment items such as mobile laboratory vans, gamma spectrum l analysis equipment, radiation survey instrumentation, and air-sampling and monitoring devices.
Based on the recommendations of the task force, each Region was equipped with complete mobilelaboratories.235In some cases, this represented upgrading certain equipment or purchasing new equipment. This action item required that revisions be made to the inspection program to include the upgrading of the independent radiological measurements. The program was included in the routine ole program for review and revision of the inspection program. As new equipment needs were identified, the program was to be revised and the equipment acquired.
This item addressed improvements in the NRC capability to make independent assessments of safety and, therefore, was considered a Licensing Issue.
O' 12/31/98 1.llt.D.2-10 NUREG-0933
Rcvision 3 O CONCLUSION With the upgrading of independent radiological measurements and the implementation of otner l recommendatKms made by the task force, all work required by this item was completed.23s.37s Thus, this Ucensing Issue was resolved.
REFERENCES l 11. NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for l Nuclear Power Plants," U.S. Nuclear Regulatory Commission, (1" Edition) November 1975, (2'd Edition) March 1980, (3d Edition) July 1981.
.16. WASH-1400 (NUREG-75/014)," Reactor Safety Study, An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," U.S. Atomic Energy Commission, October 1975.
1
- 48. NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," U.S.
Nuclear Regulatory Commission, May 1980, (Rev,1) August 1980. !
l l 55. Regulatory Guide 1.97, " Instrumentation for Ught-Water-Cooled Nuclear Power Plants to l Assess Plant and Environs Conditions During and Following an Accident," U.S. Nuclear 4 Regulatory Commission, December 1975, (Rev.1) August 1977, (Rev. 2) December 1980,
, (Rev. 3) May 1983.
O lV 57. NUREG-0578, "TMI-2 Lessons Leamed Task Force Status Report and Short-Term Recommendations," U.S. Nuclear Regulatory Commission, July 1979.
- 64. NUREG/CR-2800, " Guidelines for Nuclear Power Plant Safety issue Prioritization Information Development," U.S. Nuclear Regulatory Commission, February 1983, (Supplement 1) May 1983, (Supplement 2) December 1983, (Supplement 3) September 1985, (Supplement 4) July 1986, (Supplement 5) July 1996.
i 98.. NUREG-0737, " Clarification of TMI Action Plan Requirements," U.S. Nuclear Regulatory Commission, November 1980, (Supplement 1) January 1983.
( 149. Memorandum for J. Funches from R. Mattson, " Comments on Prioritization of Licensing I improvement issues," February 2,1983.
188. NUREG/CR-2644, "An Assessment of Offsite, Real-Time Dose Measurements for Emergency Situations," U.S. Nuclear Regulatory Commission, April 1982.
189. Memorandum for K. Goller from R. Mattson, " Proposed Changes to Regulatory Guide 1.97,* July 29,1982.
212. NUREG-0772, " Technical Bases for Estimating Fission Product Behavior During LWR Accidents," U.S. Nuclear Regulatory Commission, June 1981.
(
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Revision 3 i l l 213. Regulatory Guide 1.3, " Assumptions Used for Evaluating the Potential Radiological ,
l Consequences of a Loss-of-Coolant Accident for Boiling Water Reactors," U.S. Nuclear l Regulatory Commission, November 1970, (Rev.1) June 1973, (Rev. 2) June 1974.
214. Regulatory Guide 1.4, " Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactors," U.S.
Nuclear Regulatory Commission, November 1970, (Rev.1) June 1973, (Rev. 2) June 1974.
224. NUREG-0654, " Criteria for Preparation and Evaluation of Radiological Emergency '
Response Plans and Preparedness in Support of Nuclear Power Plants," U.S. Nuclear Regulatory Commission, February 1980, (Rev.1) November 1980.
235. Memorandum for H. Denton from R. DeYoung, "TMl Action Plan items Still Pending,"
June 10,1982. <
1 236. Memorandum for W. Dircks from R. DeYoung, "TMI Action Plan - Completed Items,"
June 30,1982.
379. Memorandum for H. Denton from R. DeYoung, " Draft Report on the Prioritization of Non-NRR TMI Action Plan items," January 24,1983.
382. Memorandum for W. Minners from R. Mattson, " Schedules for Resolving and Completing Generic Issues," January 21,1983.
384. Memorandum for T. Speis from R. Vollmer, " Schedules for Resolving and Completing Generic issues," February 1,1983.
390. NUREG-0850, " Preliminary Assessment of Core Melt Accidents at the Zion and Indian Point Nuclear Power Plants and Strategies for Mitigating Their Effects," U.S. Nuclear Regulatory Commission, November 1981.
391. Memorandum for E. Reeves from J. Knight, " Zion Liquid Pathway Analysis," August 8, 1980.
455. NUREG-0771, " Regulatory impact of Nuclear Reactor Accident Source Term Assumptions," U.S. Nuclear Regulatory Commission, June 1981.
464. NUREG-0555, " Environmental Standard Review Plans for the Environmental Review of Construction Permit Applications for Nuclear Power Plants," U.S. Nuclear Regulatory Commission, May 1979.
598. Memorandum for W. Dircks from H. Denton, "Closecut of TMl Action Plan Task Ill.D.2.5,
'Offsite Dose Calculation Manual,'" January 17,1984.
l 599. NUREG/CR-3332, " Radiological Assessment - A Textbook on Environmental Dose l Analysis," U.S. Nuclear Regulatory Commission, September 1983.
l 12/31/98 1.Ill.D.2-12 NUREG-0933
Revision 3 659. Memorandum for H. Denton from R. Vollmer, "ESRP 7.1.1 ' Environmental Impacts of 4
Postulated Accidents involving Radioactive Materials - Releases to Groundwater,'"
September 25,1984.
660. Memorandum for W. Dircks from H. Denton, " Generic Issue Ill.D.2.3 ' Liquid Pathway Radiological Control,'" October 29,1984.
799. Memorandum for W. Dircks from H. Denton, " Resolution of Generic issue Ill.D.2.3 - Liquid Pathway Studies," August 28,1985.
838. NUREG-1165, " Environmental Standard Review Plan for ES Section 7.1.1," U.S. Nuclear Regulatory Commission, November 1985.
1563. NUREG/CR-5382, " Screening of Generic Safety issues for License Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
b v
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p:
Rsvision 1 ITEM A-21: MAIN STEAM LINE BREAK INSIDE CONTAINMENT- EVALUATION OF ENVIRONMENTAL CONDITIONS FOR EQUIPMENT QUALIFICATION DESCRIPTION Safety-related equipment inside the containment of a nuclear power plant is qualified for the most severe accident conditions under which it is expected to function. In a PWR, this had been previously assumed to be the pressure and temperature that would accompany a LOCA resulting from the failure of the largest pipe in the reactor primary system. However, preliminary calculations indicated that the failure of a main steam line inside the containment could result in a temperature higher than that calculated for a LOCA and, therefore, possibly higher than the temperature for which the safety-related equipment was qualified.
This NUREG-03712 item addressed the evaluation of environmental conditions that would result from a main steam line break (MSLB) within the containment for the purpose of qualifying safety-related equipment This evaluation would involve recommending acceptable methods for i simulating and calculating the environmental conditions during component qualification testing.
PRIORITY DETERMINATION Assumptions it was assumed that the accident sequence of interest is initiated by an MSLB with the break size and location such that superheated conditions exist in some volume within containment Then, some equipment within this volume fails, since these environmental conditions are somewhat more i severe than the design basis conditions. This equipment failure then causes the MSLB accident I to result in a core-melt accident Freauency Estimate The frequency of an MSLB was estimated to be less than 10 4/RY.32 It was assumed that 20% of these breaks are of such size and location that they would produce conditions greater than design conditions in a significant volume within containment Equipment was not expected to fail if ,
temperatures were to rise slightly above the qualification temperatures. Since the temperatures '
under consideration are only on the order of 10*F hotter than the qualification temperature, the probability of equipment failure was estimated to be no more than 10%, even if the equipment were subjected to sustained temperatures of this magnitude. However, these temperatures are not sustained. Because of the relatively low heat transfer rate in superheated steam and the heat capacity of the affected equipment, the equipment itself is not expected to achieve a temperature greater than that for which it was qualified.'" This effect was conservatively bounded by assuming a probability no greater than 10% that the temperature of the equipment will surpass the qualification temperature.
Finally, it was assumed that there would be a 10% chance of equipment failure causing a core-melt accident This assumption resulted in an upper limit core-melt frequency of 2 x 10'7 /RY.
(
12/31/98 2. A.21 -1 NUREG-0933
Rcvision 1 Consecuence Estimate A core-melt can have a variety of consequences ranging from 2,000 man-rem to over 5 x 108 man-rem. Assuming the same distribution of consequences calculated in WASH-1400'8 and scaling this spectrum to 2 x 10#core-melt /RY, the resulting average risk was calculated to be 0.22 man-rem /RY. At the time of the initial evaluation of this issue in November 1983, there were 43 operating PWRs with 350 years of experience. Assuming a 40-year plant life and including 36 PWRs that were under construction, the total remaining operating life of 79 PWRs was 2,810 years. Thus, the total risk reduction for this issue was less than 618 man-rem.
Cost Estimate Industry Cost: It was estimated that $100,000/ plant of analytical work would be required to calculate temperatures throughout the containment for the entire MSLB spectrum. In addition, should equipment upgrade be necessary (which was earlier estimated to have a 10% probability),
an additional $1M or more per plant would be required. Thus, the average licensee cost was estimated to be $200,000, or $15.2M for the 76 affected PWRs.
NRC Cost: It was estimated that 3 staff-months of generic work and 1 staff-week for each of the 43 operating PWRs would be required to address the possible solution. (No extra review costs were involved in forward-fits.) Thus, the total NRC cost was estimated to be about $100,000.
Total Cost: The total industry and NRC cost associated with the possible solution was estimated to be $(15.2 + 0.1)M or $15.3M.
Value/ impact Assessment Based on an estimated public risk reduction of 618 man-rem and a cost of $15.3M for a possible solution, the value/ impact score was given by:
S < 618 man-rem
$15.3M
< 40 man-rem /$M CONCLUSION This issue was given a low priority ranking (see Appendix C) in November 1983. In NUREG/CR-5382,* it was concluded that consideration of a 20-yearlicense renewal period did not change the priority of the issue. Further prioritization, using the conversion factor of $2,000/ man-rem approved'ese by the Commission in September 1995, resulted in an impact /value ratio (R) of
$25,000/ man-rem, which placed the issue in the DROP category.
REFERENC_FJ
- 2. NUREG-G371, " Task Action Plans for Generic Activities (Category A)," U.S. Nuclear Regulatory Commission, November 1978.
O 12/31/98 2.A.21-2 NUREG-0933
Revision 1
- 16. WASH-1400 (NUREG-75/014)," Reactor Safety Study An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," U.S. Atomic Energy Commission, October 1975.
- 32. NUREG-0138, " Staff Discussion of Fifteen Technical issues Listed in Attachment to November 3,1976 Memorandum from Director, NRR to NRR Staff," U.S. Nuclear Regulatory Commission, November 1976.
186. NUREG-0510, " Identification of Unresolved Safety issues Relating to Nuclear Power Plants," U.S. Nuclear Regulatory Commission, January 1979.
1563. NUREG/CR-5382, " Screening of Generic Safety Issues for License Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
O l
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Rsvision 2 O
ITEM A-38 TORNADO MISSILES DESCRIPTION Histoncal Backaround The AEC first established missile-protection requirements in 1967. GDC-2 and GDC-4 of 10 CFR Part 50, Appendix A, require in part that structures, systems, and components important to safety be designed to be able to withstand the effects of tomado missiles. Specific design acceptance criteria to meet the requirements of GDC-2 and GDC-4 and recommended methods of satisfying the acce/us.ce criteria are dotatied in SRP" E %ns 3.3.2 and 3.5.1.4 and in Regulatory Guides 1.76* and 1.117.*
A limited reexamination of tomado missile protechon requirements in 1976 resulted in significant reduction in requirements. However, it was suggested2 that the existing tomado missile protection requirements may have been more conservative than necessary. The purpose of this NUREG-2 0371 item was to reexamine the requirements more precisely with a view to a possible outcome of adequate protection at less industry cost. The evaluation of this issue included consideration ofissue A-32.
Safety Sianificance Missiles generated by tomadoes could potentially damage systems or components containing i radioactivity or necessary for the safe shutdown of a reactor.d' This damage may directly result in the release of radioactivity to the environment or ultimately affect core cooling and result in core ;
damage or melting.
Possible Solution .
The existing tomado missile requirements included structural strengthening of potential safety-significant targets of tomado missiles, concrete missile protection for spent fuel pools, and increased concrete wall thickness around safety-class structures other than containment to stop tomado missiles.
The suggested task was to inverLgate whether postulated missile velocities, size, and orientation used in plant safety analyses we.re more conservative than tomado damage histories warranted.
The end product of this task was to be a set of design basis missiles that did not impose unnecessary design requirements on plant construction and for which a sound technical basis existed.
PRIORITY DETERMINATION Freauency Estimate This issue was addressed in WASH-1400where the findings presented were based on work by Doan.d' It was stated that the probability of energetic tomado-generated missiles would be less 12/31/98 2.A.38-1 NUREG-0933
Revision 2 than 5 x 104and that the only likely damage to sensitive plant systems would be the loss of the diesel generator building doors. The probability of this event causing a core-melt accident or any other significant radioactive release would be less than 10 .
Thus, the frequency of a core-melt accident resulting from a tomado was estimated to be 5 x 10 4
/RY or 1.5 x 104/ reactor over a 30-year operating life. Large changes to the missile criteria would not be made and the effect on core-melt frequency would be intentionally small (-10%). A 10%
increase in the core-melt frequency would be 1.5 x 104/ reactor.
Consecuence Estimate Depending on the systems or structures that are damaged, almost any type of core-melt scenario could occur. However, as a boundng estimate, it was assumed that the worst core-inelt scenarios (Release Categories PWR-1, PWR-2, PWR-3, BWR-1, and BWR-2) would occur. Although a tomado missile event is likely to be followed by high winds, typical meteorological behavior was assumed along with a mean population density of 340 people per square-mile. The release categories listed above were calculated to result in between 4 and 7 million man-rem. Therefore, the release from a tomado missile event was estimated to result in about 5 x 105 man-rem.
Assuming possible reduced (lower-cost) tomado missile protection requirements, the totalincrease 8
in risk for future reactors was estimated to be (1.5 x 10*) (5 x 10 ) man-rem / reactor or 0.08 man-rem / reactor.
Cost Estimate Industry Cost: The potential cost savings to future plants was estimated, to a rough approximation, by considering the volume of reinforced concrete potentially saved. According to an estimate from SEB/DE/NRR, tomado protection (for wind loads and missiles combined - they are not readily separable) involved roughly 2,200 cubic-yards of reinforced concrete for a typical plant. At
$900/ cubic-yard of concrete in place (based on Means, " Building Construction Cost Data,1981," i for elevated slabs, plus 15% inflation since January 1981 and 100% for NRC special l requirements), the estimated costwas about $2M/ plant. Since only modest changes to the criteria were intended, the reduction in missile resistance reflected in design parameters, such as wall thickness, would be small (again ~ 10%). A 10% saving due to reduced missile requirements would mean $200,000 saved per future plant.
NRC Cost: The proposed NRC study was estimated to cost about $300,000, basea on the NUREG-0371 2estimate of 2.4 man-years plus a $60,000 technical assistance contract. However, when amortized over more than 10 future plants, the NRC cost was small compared to industry costs. j Total Cost:
Value/ impact Assessment The estimated value/ impact score for retention of the existing tornado missile protection requirements for future plants (rather than relaxing them as discussed) was given as follows:
O 12/31/98 2.A.38-2 NUREG-0933
1 Rsvision 2 S = 0.08 man-rem / reactor j $0.2M/ reactor
= 0.4 man-rem /$M Uncertainties At the time this issue was evaluated, tomado missile protection was a recent development nearly unique to nuclear power plants and was not a matter of any long-established engineering practice.
The probabilistic estimates were widely recognized as subject to great data-base uncertainties (See NUREG/CR-2300,5p.10-1). Existing and possible modified future requirements depended heavily on engineering judgment and intuitive interpretation of limited data. However, even if the estimated frequency of a core-melt accident resulting from a tomado (which was very small) was increased by a factor of 10 or even 100, the conclusion would not change.
The magnitude of the cost savings (if any) that could be achieved, depending on the outcome of the proposed study, could not be reliably predicted at the time this issue was evaluated. At best, these savings could be bounded by consideraticn of the total cost of tornado protection. The total savings achievable would be a function of the number of future plants affected and the distribution of these plants among the three regions of the U.S. with a high incidence of tomadoes. If the cost savings were significantly smaller, the net cost savings including NRC costs would become negligible.
.Other Considerations Reduction of tomado missile protection requirements may not be fully reflected in reduced concrete wall thicknesses, etc., because, at some point, other factors such as tomado wind loadings may become controlling. Also involved here were various man-made extemal events for which specific consideration had not been required, because of reliance on tomado missile protection to provide an adequate " umbrella" of protection. These events include small aircraft crashes, missiles from offsite explosions, and physical attacks.
CONCLUSION lt was possible that further reexamination of tomado missile requirements could have led to industry cost savings due to reduction of these requirements (beyond the reductions made on the basis of the 1976 reexamination) without significant risk increase. If there was greater assurance that these cost savings would be significant and likely to be achieved (by performing a more .
detailed design and cost analysis), this issue would have warranted a high priority. However, the l savings could only be realized in those plants not yet designed or under construction. Since such new plants were possible at some indefinite future time, the issue was given a low priority ranking (see Appendix C)in November 1983. In NUREG/CR-5382,'" it was concluded that consideration of a 20-year license renewal period did not change the priority of the issue. Further prioritization, using the conversion factor of $2,000/ man-rem approved'" by the Commission in September 1995, resulted in an impact /value ratio (R) of $2.5M/ man rem, which placed the issue in the DROP category.
12/31/98 2.A.38-3 NUREG-0933
Revision 2 l l
REFERENCES
- 2. NUREG-0371, " Task Action Plans for Generic Activities (Category A)," U.S. Nuclear Regulatory Commission, November 1978.
- 16. WASH-1400 (NUREG-75/014)," Reactor Safety Study, An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," U.S. Atomic Energy Commission, October 1975.
- 41. Nuclear Safety. Volume 11, No. 4, pp. 296-308, "Tomado Considerations for Nuclear 1 Power Plant Structures including the Spent Fuel Storage Pool," P. L. Doan, July 1970. j i
- 42. Regulatory Guide 1.76, " Design Basis Tomado for Nuclear Power Plants," U.S. Nuclear l Regulatory Commission, April 1974. )
l
- 43. Regulatory Guide 1.117, "Tomado Design Classification," U.S. Nuclear Regulatory Commission, June 1976, (Rev.1) April 1978.
187. NU REG /CR-2300, "PRA Procedures Guide," U.S. Nuclear Regulatory Commission, (Vols.
1 and 2) January 1983.
1563. NUREG/CR-5382, " Screening of Generic Safety issues for License Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
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Revision 1
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ITEM D-1: ADVISABILITY OF A SEISMIC SCRAM DESCRIPTION Historical Backaround .
l This issue is described in NUREG-04718 and was raised by the ACRS who recommended that-studies be made of the technique for seismic scram and the potential safety advantages and disadvantages of prompt reactor scram, in the event of strong seismic motion.
Safety Siondicance A seismic scram could be designed to scram the reactor upon the occurrence of a seismic event, )
before turbine trip or other conditions resulting from the seismic disturbance could cause a scram.
l The earlier scram could give a lead time between 5 to 20 seconds. The lead time could provide resulting benefits such as reduced loads during the seismic event and, therefore, less burden on the plant systems, it may also reduce the likelihood of a LOCA or severe transient after a seismic event. j l
Possible Solution j An automatic seismic trip system could be designed to utilize existing state-of-the-art seismic instrumentation. The system could be designed to use coincidence logic to reduce the frequency ,
of spurious trips. A "high level" trip could be set based on some percent of the SSE (usually chosen as greater than 60% of the SSE level) and could be designed to minimize spurious trips due to after-shock and low acceleration earthquakes. A " low level" trip would be set to activate on the compressional waves (P waves) when this first arrival caused displacement or acceleration greater than the calculated maximum allowable P wave for an OBE.
PRIORITY DETERMINATION Assumptions The " low level"and "high level" trips assumed were described in UCRL-52156"" and Supplement 2 to NUREG/CR-2800,"respectively. To select an upper bound on the potential for risk reduction from resolution of the issue, the analysis in NUREG/CR-2800" was chosen because it showed the largest potential advantage and was based on a "high level" trip point.
To identify the possible advantages of a seismic scram system, possible transient and accidents
. that could lead to core-melt were considered. It was then assumed that the early seismic scram precluded waiting for a later trip and it would, therefore, reduce transient pressure and loads and the heat generation rate ir. ihe core. It was then assumed that this would decrease the burden on the reactor's safety systems, e.g., safety / relief valves and turbine-driven pumps, it was also assumed that, in the event of a LOCA, an earlier trip could reduce the fuel rod temperature transient and the containment vessel pressure. Less fluid would be lost during the blowdown 12/31/98 2.D.1-1 NUREG-0933
Revision 1 phase before the SIS operating pressure is reached. To quantify these benefits, these assumptions were converted to a frequency reduction for certain event initiators.
Frecuency Estimate The assumption was made that the prime benefit of an earlier seismic scram is in reducing the frecuency of a seismically-induced transient or LOCA initiator as a result of reduction in the afore-mentioned stresses. Therefore, the core-melt frequency due to an earthquake (where the earthquake's only effect is to induce a transient or LOCA initiator) was estimated. This estimate8d was based on an LLNL Report (UCRL-53037) which provided estimates of earthquake frequency at the Zion site and the conditional probabilities of transient or LOCA initiators, given an earthquake.
Earthauake Freauency at Zion Site (Durina Plant Operation)
Earthquake Frequency /RY Level (SSE) 0.4 - 0.6 8.4 x 10d 0.6 - 0.9 4.5 x 10 d 0.9 - 1.8 2.5 x 10d 1.8 - 2.5 1.3 x 10 4
>2.5 2.2 x 10 4 Conditional Probabi[tv of Transient or LOCA Initiator (Given an Earthauake)
Earthquake Conditional Probability Level (SSE) LOCA T, Transient T Transient 0.6 - 0.9 6.0 x 10 4 0.360 0.24 0.9 - 1.8 2.5 x 10 4 0.400 0.59 1.8 - 2.5 5.2 x 102 0.019 0.93
>2 5 2.6 x 10-' O 0.74 Since no data were provided on the conditional probability of transient or LOCA initiators for 0.4 to 0.6 SSE, no contribution was estimated for this SSE interval. Based on these tables, the following frequencies of seismically-induced transient or LOCA initiators were calculated:
d 4 4 LOCA = (4.5 x 10 /RY)(6 x 10 ) + (2.5 x 10 /RY)(2.5 x 104) 4
+ (1.3 x 10 /RY)(5.2 x 10 2) + (2.2 x 104/RY)(2.6 x 10- )
12/31/98 2.D.1-2 NUREG-0933
Rsvision 1
= 1.9 x 104/RY
\
l d 4 4 T, = (4.5 x 10 /RY)(0.36) + (2.5 x 10 /RY)(0.40)+ (1.3 x 10 /RY)(0.019)
= 2.7 x 1 Y/UY d 4 T2 = (4.5 x 10 /RY)(0.24) + (2.5 x 10d/ RY)(0.59) + (1.3 x 10 /RY)(0.93)
+ (2.2 x 104/RY)(0.74)
= 2.6 x 10d/RY The accident sequences were defined based on the Oconee-3 and Grand Gulf-1 risk equations I in NUREG/CR-2800," and the affected release category and core-melt frequencies were:
Q9.90ft 1 Grand Gulf-1
' (PWR-1), = 1.4 x 10*/RY (BWR-1), = 8.5 x 10-"/RY (PWR-2), = 3.3 x 104/RY (BWR-2), = 1.7 x 104/RY
'(PWR-3), = 4.3 x 10 e/RY (BWR-3), = 1.4 x 10*/RY (PWR-4), = 9.3 x 10 "/RY (BWR-4), = 1.4 x 104/RY (PWR-5), = 1.2 x 104/RY (PWR-6), = 8.2 x 104/RY (PWR-7), = 1.3 x 10#/RY lt was then assumed that a high-level scram could reduce the frequencies of all these sequences, with the exception of those for which failure to scram is an inherent part of the sequence, by reducingthefrequenciesof theirseismically-inducedinitiators.Removingthecontributionfromthe two failure-to-scram sequences from the totals for all these sequences, the following maximum frequency reductions were calculated based on total elimination of seismically-induced transients and LOCAs.
AF = 1.8 x 10#/RY Oconee-3:
Grand Gulf-1: AF = 2.0 x 10*/RY Consecuence Estimate To calculate the risk reduction (AW), the dose factors from Appendix D of NUREG/CR-2800" were used with the following results: '
Oconee-3: AW = 0.26 man-rom.9Y Grand Gulf-1: AW = 0.13 man-re.n uRY The total public risk reduction was then calcu!ated as follows:
AW. = (0.26 man-rem /RY)(85 PWRs) (28.8 years) + (0.13 man-rem /RY)(44 BWRs)(27.4 years)
= 790 man-rem
.Qost Estimate Industry Cost: It was assumed that 10 man-weeks of labor would be required to install and test the seismic scram system and that it could be performed during scheduled outages. The labcr was assumed to cost $2,270/ man-week and equipment was assumed to cost $150,000/ plant.
\
12/31/97 2.D.1-3 NUREG-0933
Rnvision 1 Therefore, the total implementation cost for 129 plants was estimated to be about $22M. The total cost for operation and maintenance was estimated to be $33M, based on 4 man-weeks /RY. Thus, the totalindustry cost was estimated to be $(22 + 33)M or $55M.
NRC Cost: NRC costs were assumed to be negligible compared to industry costs.
Total Cost: The total industry and NRC cost associated with the possible solution was estimated to be $55M.
Value/ impact Assessment Based on an estimated public risk reduction of 790 man-rem and a cost of $55M for a possible solution, the value/ impact score was given by:
S = 790 man-rem
$55M
= 14 man-rem /$M Other Considerations (1) At the t;me of the initial evaluation of this issue in November 1983, San Onofre and Diablo Canyon had seismic scram systems installed.
l (2) Another advantage suggested in Supplement 2 to NUREG/CR-2800"was a slight addition of time for some core-melt scenarios. This was not included in the above analysis because it was not believed to be a significant amount of time in relation to preventing core-melt.
(3) Potential disadvantages of a seismic scram are spurious trips due to maintenance or test, and possible trips when a trip would not be necessary, i.e., the plant would ride through an event. Through careful design, these could be minimized.
(4) A number of critical comments *8A87were made regarding the LLNL study (UCRL-53037) that was used in the NUREG/CR-2800" analysis. These comments indicated that the report was too optimistic regarding the benefits of a seismic scram.
i CONCLUSION This issue was given a low priority ranking (see Appendix C) in November 1983. In NUREG/CR-5382,"8 it was concluded that consideration of a 20-year license renewal period did not change j the priority of the issue. Further prioritization, using the conversion factor of $2,000/ man-rem approved 1689 by the Commission in September 1995, resulted in an impact /value ratio (R) of
$71,428/ man-rem, which placed the issue in the DROP category.
REFERENCES 1
- 3. NUREG-0471, " Generic Task Problem Descriptions (Categories B, C, and D)," U.S.
Nuclear Regulatory Commission, June 1978.
O 12/31/98 2.D.1-4 NUREG-0933
. _ . ~ . _ .._.o
Ravision 1 l l
- 64. NUREG/CR-2800, " Guidelines for Nuclear Power Plant Safety Issue Prioritization O(/ Information Development," U.S. Nuclear Regulatory Commission, February 1983, (Supplement 1) May 1983, (Supplement 2) December 1983, (Supplement 3) September 1985, (Supplement 4) July 1986, (Supplement 5) July 1996.
486. Memorandum for Z. Rosztoczy, et al., from W. Anderson, " Seismic Scram," January 20, 1983.
487, Memorandum for G. Amdt from G. Burdick, " Review of Seismic Scram Report, UCRL-53037," March 3,1983.
1563 NUREG/CR-5382, " Screening of Generic Safety issues for Ucense Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
i 1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per I Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294)," l September 18,1995. I 1717. UCRL-52156," Advisability of Seismic Scram," Lawrence Livermore Laboratory, June 30, 1996. 1
(
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' ISSUE 35: DEGRADATION OF INTERNAL APPURTENANCES IN LWRs DESCRIPTION Historical Backaround This issue was identified ** after AEOD completed a study on intamal appurtenances in LWRs. i This study, AEOD/E101,d7 was initiated because of the relatively high number of LERs that I described events in which intamal appurtenances (flow straighteners, orifices, diffusers, etc.) in the secondary system piping became loose or dislodged.'"
i Safety Sionificance I i
Originally, the safety concem was that, if a steam line break were to occur in a PWR, any loose objects in the secondary piping could become missiles during the steam generator blowdown and rupture one or more steam generator tubes.42e A combined SGTR and MSLB'was not a design basis accident. However, the issue was broadened to include loose objects in all LWRs, presumably in all locations. With such a broad definition, it automatically followed that there was a relatively large number of safety aspects. In general, a loose object causes problems either by causing impact damage or by blocking flow. In addition, the presence of a loose object of intemal origin automatically implies that the system or component from which the loose object originated becomes degraded.
Concem with looss objects was by no means new since issue B-60, " Loose Parts Monitoring System," extensively studied the occurrence and safety significance of loose objects within the primary system. Therefore, the evaluation of issue 35 did not include the primary system. In addition, degradation of the ESFs was not considered since the generalissue of ESF reliability l was addressed in otherissues, e.g., Issues A-45, B-4, and ll.E.3.2. Moreover, since ESFs are not 1 in operation during normal operation of a plant, degradation of intemal appurtenances in service should not be a problem. Thus, the only concem that remained to be evaluated was the secondary system, the focus of the AEOD study.d7 l
In addition to the MSLB/SGTR scenario described above, a loose or disengaged object in the l secondary system can have additional safety significance such as:
(1) A loose object in the feedwater system can cause a loss-of-feedwater transient.
(2) A sufficiently massive object could cause a feedwater line break.
(3) A loose object in the main steam system could cause a transient. In many plants, plugging or isolating the main steam lines will also cause loss of main feedwater. A massive object could cause a steam line break.
(4) A loose object in a PWR steam generator could cause an SGTR.
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i R: vision 2 (5) A loose object could prevent containment isolation valves from closing in the event of an accident.
(6) A loose object could conceivably cause a small LOCA in non-safety systems connected to the primary system (e.g., RWCU System). These are primary rather than secondary systems which were not covered in Issue B-60 and thus remained within the scope of Issue 35.
Possible Solutions The systems considered were comprised primarily of piping rather than plenums and thus were not amenable to the loose parts detection program required by issue B-60. About all that could be done was more frequent inspection and/or greater care in design and assembly, each where appropriate.
PRIORITY DETERMINATION Freauency/Consecuence Estimate Each of the scenarios described under Safety Significance above was examined.
1 (1) Steam Line Break with SGTR The frequency of a steam line break was estimated to be s104/RY, about 10% of which was expected to occurwithin containment (See issue A-22). Assuming this frequency, the probability of a loose part being present at the time of the break was needed. AEOD +
studiesss2.c listed 12 such events as of June 15,1982, which corresponded to 360 PWR- !
years. It was assumed that these reported events constituted 20% of the total events. In addition, it was assumed that a loose object wouid go unnoticed for 2 years, i.e., at least !
a complete reload cycle. The probability of a loose object being present,during such a two- ;
year period was estimated using the Poisson formula: '
P = 1 - exp-[(12 recorded events)( 1 actual event )(2 years))
360 years 0.20 recorded events l
= 0.28 l
It was further assumed that, given an MSLB event and a loose part present somewhere j in the steam generator feedwater lines, there was a 10% chance of the loose object t rupturing a steam generator tube. Using these numbers, an event tree was constructed.
l Branches accounted forwhether the break was inside or outside containment, whether the !
MSIV closed or not, whether feedwater to the affected steam generator was shut off, and j whether the HPSI system operated of failed. The result was:
I 4
Core-melt /PWR-year = 8.7 x 10 l Man-rem /PWR-year = 0.32 l
The dominant sequence was as follows: i O
12/31/98 3.35-2 NUREG-0933
Rsvision 2 Steam line break occurs 104/PWR-year V Loose objectis present 0.28 Steam generator tube (s) rupture 0.10 Break is inside containment 0.10 MSIV is closed 0.90 Feedwater to affected steam generator continues (containment fails due to overpressure) 0.10 HPSI successfully cools core, but noble gases and some iodine are released 0.98 Net pir,bsbility 2.5 x 10#/PWR-year Release is - PWR-8 7.5 x 10d man-rem Net risk for this sequence 0.20 man-rem /PWR-year (2) Loss of Feedwater Transients and Transients Induced by Loose Obiects in the Steam Lines AEOD studiesas2.4aa listed 17 events of this nature in a period covering about 600 RY.
Thus, the frequency of reported events was 17/B00 per reactor-year, or 2.8 x .10-2 /RY.
Again, there was probably a sizable number of loose objects that were not reported.
However, not all ioose objects cause transients and those that do probably were expected to be reported. Thus, the frequency of transients was estimated to be the same as the frequency of reported events, 2.8 x 10-2/RY. Such transients normally have no safety consequences. However, they can initiate an acodent if other equipment fails. To estimate risk, the frequencies of the transient-initiated sequences in Tables V 3-14 and V 3-16 of WASH-1400 were scaled to match the frequency estimated above. The results are shown below in Table 3.35-1.
Table 3.35-1 Release Frequency /RY Consequences Category (man-rem)
PWR-1 8.1 x 104" 5.4 x 10' PWR-2 8.1 x 10 4 4.8 x 108 i PWR-3 1.1 x 10* 5.4 x 108 PWR-4 1.9 x 104' 2.7 x 10e PWR-5 5.4 x 104* 1.0 x 108 PWR-6 5.4 x 104 1.5 x 108 PWR-7 2.7 x 10 4 2.3 x 108 BWR-1 2.7 x 104 5.4 x 108 BWR-2 1.6 x 10 4 7.1 x 10' BWR-3 5.4 x 10 4 5.1 x 10 8 BWR-4 5.4 x 104 6.1 x 105 12/31/98 3.35-3 NUREG-0933
Revision 2 Core-melt Frequency: 4.3 x 104tPWR-year 7.8 x 104/BWR-year Public Risk- 0.051 man-rem /PWR-year 0.41 man-rem /BWR-year (3) Feedwater Line Break and Steam Line Break The frequency of line breaks due to loose objects was very small, since these lines are quite massive. Nevertheless, steam flows through steam lines at roughly 300 mph and a loose object traveling with the flow would have considerable impact when it encounters a 90* bend. The result, if there is damage, would likely be a hole punched in the piping rather than a complete circumferential break.
It was assumed that the frequency of line breaks was 1% of the frequency of transients estimated above. This resulted in an estimated break frequency of 2.8 x 10d /RY. Although this numberwas judgmentalin nature, if the actual frequency were an order of magnitude higher, two steam line breaks would have occurred in the 630 RY accumulated at the time the issue was initially evaluated.
In PWRs, sieam line breaks outside of containment are not particularly significant from the point of view of the reactor. The licensing analysis of such an event concentrates on the cooldown reactivity transient (and associated radiological consequences), assuming a complete circumferential break, end-of-cycle moderator temperature coefficients, and failure of the highest worth control rod to insert. It is most unlikely that a loose object would ,
cause a complete circumferential break, regardless of the probabilities of the other j assumptions of the licensing basis. It should also be noted that opening an ADV is !
equivalent to a steam line break passing 10% of rated steam generator flow. Feedwater i line breaks outside containment are still more innocuous, since check valves will prevent i blowdown of the steam generator. j I
inside containment, breaking a steam line will dump the mass and energy content of a i steam generator to the containment. If feedwater to this steam generator is not cut off, continued steam production could endanger the containment. (Feedwater line breaks are less troublesome, since breaking the feedwater line is guaranteed to shut off feedwater to the steam generator which is blowing down.)
This was exactly the safety concem of issue A-22, "PWR Main Steam Line Break - Core, Reactor Vessel, and Containment Response." If the priority parameters calculated for issue A-22 were scaled to the frequency of 2.8 x 104/PWR-year estimated for a break inside containment, the result would be: j i
Core-melt Frequency: zero ;
Public Risk- s 0.00038 man-rem /PWR-year l 1
In BWRs, steam line breaks and feedwater line breaks are small LOCAs. In view of the !
presence of two MSIVs in each steam line and two check valves in each feedwater line in a BWR, only breaks inside containment were considered. Again, the estimated frequency was 2.8 x 104/BWR-year, just as in the PWR case. In addition, it was assumed that the 12/31/98 3.35-4 NUREG-0933
Ravision 2 break was an "S," LOCA (equivalent diameter of 2 to 6 inches). The following values were
( obtained by scaling Table V 3-16 of WASH-1400 to 2.8 x 10 4 "S," event /BWR-year.
Release Frequency /RY Consequences Category (man-rom)
BWR-1 9.3 x 10"* 5.4 x 108 BWR-2 8.4 x 10* 7.1 x 10 8 BWR-3 1.9 x 10 4 5.1 x 10e BWR-4 1.9 x 10 4 6.1 x 105 Core-melt Frequency: 3 x 104/BWR-year Public Risk: 0.16 man-rem /BWR-year (4) SGTR This particular scenario was addressed in the steam generator tube integrity issues A-3, A-4, A-5,66, and 67 and was not considered further in this issue.
(5) Loss of Containment Isolation Caoability Loose objects can interfere with valve operation, particular1y since valve seats are natural collection points for debris. Most valves in the secondary system are not safety-related; ,
interference with these valves will at most cause a transient, as discussed earlier. The safety-related valves include steam safety valves and isolation valves. Of these, the steam safeties are not susceptible to damage by loose objects under normal circumstances, since there is no flow to carry objects into them nor are most loose objects likely to float upwards in steam. Even if a loose object were carried into a safety valve during a safety valve actuation, the overpressurization analysis assumed one failed valve. Thus, a loose object plugging one safety valve would not result in overpressurization of the secondary side.
Interference with isolation valves (preventing complete closure) is more plausible, since these valves are usually passing flow during normal operation. AEOD studies 52.433 listed only one event of this nature in a period of 600 RY. Since isolation valves are tested periodically and problems are reportable, it was unlikely that the actual number of events was significantly larger than the number of reported events. Thus, it was expected that the frequency of occurrence of an inoperable isolation valve due to a loose object would be on the order of 1.7 x 10 /RY.
The longest interval between isolation valve tests is a full 18-month fuel cycle. A simple application of the Poisson formula produced a probability estimate of 2.5 x 10' for the failure of an isolation valve somewhere in the plant to close on demand. Failure of an isolation valve does not automatically mean that the containment fails to isolate, since there are double isolation valves on primary systems and even secondary system isolation p valves are usually backed up by check valves, turbine stop valves, etc. However, the 12/31/98 3.35-5 NUREG-0933
Rcvision 2 potential for a common mode failure is quite high for loose part events. It was assumed that failure of one isolation valve would result in failure of the containment to isolate.
The effect of a containment isolation failure of this nature was to change accident scenarios, which otherwise would have resulted in Release Category PWR-7 or PWR-9, into Release Categories PWR-5 or PWR-8, respectively. Using the WASH-1400'8 frequencies for PWR-7 and PWR-9, a multiplication by the estimated containment isolation ,
failure probability gave the change in the PWR-5 and PWR-8 frequencies:
PWR-7, -9 Containment PWR-5, -8 PWR-5, -9 Public Risk FrequencyNear Failure FrequencyNear Consequences (man-remlyear)
Probability (man-rem) 4 x 10 4 2.5 x 10-3 1.0 x 10 # 1.0 x 10e 0.100 4 x 10d 2.5 x 10 4 1.0 x 10 4 7.5 x 10 4 0.075 Core-melt Frequency: zero Public Risk: 0.175 man-rem /PWR-year .
l' The corresponding calculation for BWRs was more difficult. The analog of the PWR-7 to PWR-5 case, which corresponded to a jammed isolation valve releasing core-melt activity which would otherwise be trapped within containment, did not exist for a BWR, since BWR core-melts were expected to cause containment overpressurization and failure anyway.
The analog of the PWR-9 to PWR-8 case, which corresponded to a jammed isolation valve releasing contaminated containment atmosphere during and after a successfully mitigated LOCA, existed in theory, but no appropriate BWR release category had been calculated.
The pragmatic assumption was made that the BWR analog of the PWR-9 to PWR-8 case will result in roughly the same radiological release.
Public Risk: 0.075 man-rem /BWR-year (6) Small LOCA in System Connected to Primary AEOD studies s23 I sted one loose object in a system connected to a PWR primary loop.
In 360 PWR-years, the frequency of reported loose object events was estimated to be 2.8 x 10-8 /PWR-year. If these represented 10% of the actual events, the actual event frequency was 2.8 x 10-2/PWR-year.
In BWRs, all systems are connected to the primary side and the definition of systems needed some modification. Here, it meant systems connected to the reactor, exclusive of the main steam, condensate and feedwater, and normally idle safety systems. No such loose objects had been reported. Therefore, it was assumed that the rate of occurrence would be the same as for PWRs: 2.8 x 102/RY.
Flow rates for such systems are low. Moreover, they are equipped with various types of leak detection coupled with automatic isolation. Therefore, it was very unlikely that a loose object would cause an unisolated leak. It was assumed that the probability of such a leak was on the order of 104, given the presence of a loose object. Thus, the overall frequency 4 12/31/98 3.35-6 NUREG-0933
r Revision 2 of the leak was estimated to be on the order of 2.8 x 104/RY. The size of such a LOCA
( would be in the "S2" class. Scaling WASH-1400 Tables V 3-14 and V 3-16 to this '
frequency, the results are shown below in Table 3.35-2.
TABLE 3.35-2 Release Frequency /RY Consequences Category (man-rom)
PWR-1 2.8 x 10* 5.4 x 108 PWr2 t- 8.4 x 10* 4.8 x 108 PVfh3 8.4 x 10 4 5.4 x 10e ,
PWR-4 8.4 x 104 2.7 x 108 PWR-5 8.4 x 104 1.0 x 108 PWR-6 5.6 x 10 4 1.5 x 105 PWR-7 5.6 x 10-7 2.3 x 108 BWR-1 5.6 x 10-' 5.4 x 108 BWR-2 2.8 x 104 7.1 x 10' x BWR-3 1.1 x 104 5.1 x 10 8 BWR-4 1.1 x 104 6.1 x 105 Core-melt Frequency: 7.3 x 10 7/PWR-year l 1.5 x 104/BWR-year l
Public Risk: 0.63 man-rem /PWR-year 0.08 man rem /BWR-year The scenarios above added up to the following:
Core-melt Frequency: 8.6 x 10 7/PWR-year 1.2 x 10-7/BWR-year Public Risk: 1.18 man-rem /PWR-year 0.73 man-rem /BWR-year At the time of the initial evaluation of this issue in February 1984, there were 95 PWRs and 47 i BWRs operating, planned, or under construction, with an estimated, aggregate remaining life of 3,400 PWR-years and 1,600 BWR-years, respectively. This allowed the following estimates to be made:
Man-rem / Reactor = 40 1 Man-rem, Total = 5,000
. Core-melt /RY = 6 x 10-7 Core-melt / Year = 9 x 10 4 12/31/98 3.35-7 NUREG-0933
)
Rcvision 2 i Cost Estimate industry Cost: It was postulated that 10 man-weeks spent on inspections every refueling outage would be about 90% effective in revealing degraded appurtenances. If refuelings occurred every 18 months, this cost would be $13,300/RY. The cost of actual repair, replacement, or upgrading ,
was not included since this would eventually have to be done anyway. It should also be noted that I avoiding even one unnecessary reactor scram would pay for 20 years of inspections. Thus, there l was some actual financial advantage to licensees. Based on a remaining lifetime of 5,000 RY for all reactors, the total industry cost for the solution to this issue was $66.5M.
NRC Cost: NRC costs were estimated to be about $500,000 (5 man-years). This estimate was higher than usual since, at the time of the initial evaluation of the issue, licensing effort did not emphasize BOP systems and opposition and delay were likely.
Total Cost: The total industry and NRC cost associated with the possible solution was estimated to be $(66.5 + 0.5)M or $70M.
Value/ impact Assessment Based on an estimated public risk reduction of 5,000 man-rem and a cost of $70M for a possible solution, the value/ impact score was given by:
S = 5.000 man-rem
$70M
= 70 man-rem /SM Uncertainties None of the scerarios described above were dominant; however, all followe,d much the same pattern. The estimated frequency of loose part occurrences was unlikely to be more than a factor of 10 too low or too high. The prot' ability of a loose part causing an accident (purely judgmental estimates) might be uncertain by as much as a factor of 20 in some cases. The estimates of consequences should be within a factor of five. Finally, the estimates of cost could have been off by a factor of 10. If log normal distributions were assumed, the man-rem and core-melt figures would have been within a factor of about 60 and the priority score within a factor of 100.
CONCLUSION Based on Appendix C, the core-melt / year estimate was barely in the medium priority range (because of the large number of plants affected) and all others factors were in the low priority range. Therefore, the issue was given a LOW priority ranking in February 1984. In NUREG/CR-5382,'588 it was concluded that consideration of a 20-year license renewal period could change the ranking of the issue to medium priority. Further prioritization, using the conversion factor of
$2,000/ man-rem approved'888 by the Commission in September 1995, resulted in an impact /value ratio (R) of $14,285/ man-rem, which did not affect the low priority ranking.
O.
12/31/98 3.35-8 NUREG-0933
i l
Revision 2 REFERENCES
.16. WASH-1400 (NUREG-/5/014)," Reactor Safety Study, An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," U.S. Atomic Energy Commission, !
October 1975. 1 I
- 47. Memorandum for H. Denton from C. Michelson, " Degradation of intemal Appurtenances i in LWR Piping," January 19,1981.
352. Memorandum for C. Michelson from E. Brown, "intemal Appurtenances in LWRs," )
December 24,1980. l l
368. Memorandum for ACRS Members from C. Michelson, " Failure of a Feedwater Flow Straightener at San Onofre Nuclear Station, Unit 1," June 13,1979.
429. Memorandum for J. Knight from E. Sullivan, " Review ACRS Consultant Report," January 10,1980.
433. Memorandum for C. Michelson from E. Brown, " Degradation of Intemal Appurtenances and/or Loose Parts in LWRs," June 15,1982.
493. Memorandum for C. Michelson from H. Denton, " January 19,1981, Memorandum on Degradation of Intemal Appurtenances in LWR," April 30,1981.
1563. NUREG/CR-5382, " Screening of Generic Safety issues for License Renewal
( Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the ;
Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
I 1
12/31/98 3.35-9 NUREG-0933
R: vision 2 ISSUE 71 FAILURE OF RESIN DEMINERALIZER SYSTEMS AND THEIR EFFECTS ON NUCLEAR POWER PLANT SAFETY DESCRIPTION Histoncal Backaround This issue was raised8 by DSI/NRR in August 19828 following a search of LERs which suggested that additional licensing attention was needed for certain ancillary power plant equipment. The available information showed that failures of resin bed domineralizer sub-systems occurred within the process systems (both nuclear and non-nuclear) of nuclear power plants.
These process systems, by definition, do not directly perform any reactor protection or engineered safeguard functions, yet their failure could seriously impair the capability of safety grade systems to perform by rendering their redundant trains inoperable (i.e., causing a common mode failure).
The chief concem was the possibility that these types of events may not be bounded by the current licensing basis for nuclear power plants and could cause plants to be inadequately protected. The types of failures considered were: (1) introduchon of resin into other areas of the system (either by breakthrough of the resin during normal operation or by improper recharging);
(2) introduction of gas into other areas of the system by improper recharging; and (3) loss of water chemistry.
Safety Sionificance Failures of resin domineralizers can be caused by operator error or by equipment failure and have produced the following: (1) clogging of pump strainers (due to resin introduction into the system) and the subsequent tripping of the pumps; and (2) introduction of gas into systems (subsequently causing pump trips) due to improper domineralizer back-flushing. Systems containing demineralizers are:
PWR (a) Chemical and Volume Control System (b) Condensate and Feedwater System (c) Component Cooling Water System (d) Service Water System (e) Spent Fuel Pool Cooling and Purification System Two failure modes were considered: (1) introduction of resin or gas into a system which subsequently causes one or more additional failures; and (2) loss of water chemistry control which affects corrosion rates. The first failure mode can be caused by operator error or by equipment failure and has the potential of affecting the following systems:
PWR (a) High Head Safety injection System (b) Condensate and Feedwater System (c) RHR System .
(d) Containment Spray System
\
12/31/98 3.71-1 NUREG-0933
l Revision 2 1
(e) Chemical and Volume Control System I (f) Component Cooling Water System '
(g) Spent Fuel Pool Cooling and Purification System l BWR (a) Sensor Output from Reactor Protection System i (b) Condensate and Feedwater System (c) RHR System (d) Containment Cooling System (e) Reactor Water Cleanup System (f) Emergency Equipment Cooling Water System (g) Fuel Pool Cooling and Cleanup System Since some of these systems perform a safety function or support systems which perform a safety function, their failure could reduce the ability of a plant to maintain safe shutdown conditions. The following are a few examples of where demineralizer failures caused a loss of safety grade equipment.
(1) Following a review of a TMI-2 event that occurred in September 1977 during hot functional testing prior to fuel loading, it was concluded that, had the reactor been fueled and at power when the event occurred, there might have been core uncovery followed by fuel damage.5" TMI-2 has a full-flow, condensate polishing system in the condensate and feedwater system and, as a result of its malfunction, resin from the system was carried ,
over into the plant's deminemlized water system from which it migrated to all other parts of the plant, including the nuclear steam supply system and the turbine. The most l significant result was that the resin clogged the strainers to all of the circulating pumps in i the nuclear service closed cooling water system causing them to trip. This removed essential cooling water from all related reactor pressure and ESF systems and components and also all non-essential nuclear systems and components,i.e., RCPs, spent fuel coolers, instrument air compressors, and after-coolers. The loss of coolant to the RCPs caused the pumps to trip and the pressurizer heaters to shut off resulting in depressurization of the reactor coolant system. Itwas concluded that the net result of the polishing system malfunction was the potential loss of primary system heat removal l capability, i.e., forced convection using RCPs, natural circulation cooling, and feed-and-bleed using HPSI pumps.
(2) During RHR operation at cold shutdown at San Onofre-2, there was a system malfunction or operator errorwhile reprocessing of a demineralizer subsystem.ur2 During this operating l mode, the demineralizers of the related CVCS were lined up with the RHR to accomplish i RCS cleanup and pressure control. Backflushing of one of the related filters was initiated and, during this process, by either system malfunction or operator error, nitrogen gas used during this procedure passed through the subsystem into the suction lines of all the RHR pumps with resultant loss of operability. The RHR pumps are also the LPSI pumps. In this case, redundant systems important to protection of the facility during an accident, as well as orderly cold shutdown of the plant from 350*F, were rendered inoperable.
(3) At Pilgrim-1, there was a system malfunction which caused an improper recharging of a demineralizer in the RWCS."73 This resulted in resin entering the RCS and caused the l indicated flow rate input to the APRM flow bias trip settings to read high, thus providing a 12/31/98 3.71-2 NUREG-0933
Rsvision 2 l
( non-conservative input to two trip functions. In this case, a domineralizer problem affected the ability of a safety system to perform its function.
The loss of the ability to shut down or to maintain a safe shutdown condition for the reactor is considered of highest safety significance and the effect domineralizer failures could have on public risk associated with core-melt were evaluated below. The loss of spent fuel cooling and water cleanup capability was assumed to be of much less safety significance due to the long lead time available to restore cooling. Therefore, it was not considered a large contributor to risk and was not evaluated below.
The second failure mode (loss of water chemistry control) has the potential of changing the corrosion rate for the affected system. However, since a loss of water chemistry and the subsequent change in corrosion rate do not lead to immediate failures, do not affect all parts of the system at the same rate, and can be detected and corrected prior to having any significant impact, this failure mode was not considered a significant contributor to public risk and was not considered further below.
Therefore, based on the above, the rest of this evaluation addressed the failure mode of resin or gas introduction into a system which then leads to immediate failures of other safety systems.
Possible Solutions Possible solutions included hardware and administrative changes. Specifically, a combination of the following could be done: (1) install filters on the outlet of all domineralizer units which would stop resin from entering the system through the demineralizer outlet nozzle; and (2) evaluate
~
)
existing procedures, job aids, and training to discem where improvements can be made to l enhance operator capability and further reduce the chances for human error which result in resi,1 '
or gas intrusion into a system during domineralizer racharging. !
l PRIORlW DETERMINATION Assumotions No provision was made in the safety analysis of the operating LWRs to account for the effects or consequences of demineralizer problems or failures. Therefore, by considering the possibility of demineralizer failures, the additional risk these present to the public must be determined. The system failure probabilities used were those summarized in NUREG/CR-2800" and were based on the Oconee-3 PRA for PWRs and the Grand Gulf-1 PRA for BWRs. The number of plants .
affected by this issue was conservatively assumed to be all operating and planned plants (78 PWRs and 39 BWRs) and their average remaining life was assumed to be 30 years.
Freauency Estimate The frequency of demineralizer failures was estimated using data from an LER search for the period June 1982 through June 1984. LERs prior to 1982 were not searched since old data did not reflect existing operating practice and improvements in procedures, training, etc., subsequent to TMI-2 and, therefore, may not have been an accurate estimate of failure rate.
12/31/98 3.71-3 NUREG-0933
l Rovision 2 From the LER search, it was determined that there were 15 events involving abnormalities caused by demineralizer-related problems. Of these 15 events,2 led to degradation of a safety system.
(See References 516,1172,1173.) An additional LER search covering the years from 1984 through 1987 was performed to identify LERs that involved demineralizer systems; no additional LERs were identified involving demineralizers that caused a degradation of a safety system. The span from 1982 through 1987 comprised 277 PWR-years of operating experience. Hence, for PWRs, the frequency of safety system failure due to demineralizer problems was 2 failures in 277 PWR-years or 7.2 x 104failure / RY. For BWRs, there were no recorded LERs involving the loss of safety systems resulting from demineralizer problems. However, the event describedur2 at San Onofre-2 could have occurred in a BWR. Hence, for BWRs, it was assumed that one failure occurred over the span of 166 BWR-years or 6.2 x 104failure /RY.
In the 1984 through 1987 LER assessment, 3 events involving BWRs were found to have occurred which resulted in either an automatic or manual scram. These scrams were the result of high main steam line radiation readings which were believed to be due to either resin or corrosion particles. It was conceivable that all 3 could have resulted from resin particles. Assuming 3 transient events in the 116 BWR-years resulted in 0.026 transient per BWR-year due to demineralizerfailures. PWRs were not susceptible to these same occurrences. However, a PWR scram was found which resulted from a demineralizer fault. In the TMI-2 accident, sis the loss of feedwater resulted in a scram. With one transient trip in 227 PWR-years, a transient frequency of 3.6 x 104event /RY resulted from demineralizer-related events.
Consecuence Estimate Demineralizer system failures and their resulting impact on other plant systems cannot, by -
themselves, lead to a core-melt or containment failure. They can, however, remove some of the systems which provide lines of defense against such core-melt and containment failure events, or result in transient-induced scrams. In the case of PWRs, the systems which provide a line of defense and which could be rendered inoperable due to a demineralizer failure are: High Head Safety injection System (for reactor shutdown); Condensate and Feedwater System (for normal decay heat removal); RHR System (for shutdown decay heat removal); and Containment Spray System (for containment pressure and temperature control). For BWRs, the systems are: Reactor Protection System (for reactor shutdown); Condensate and Feedwater System (for normal decay heat removal); and RHR System (for shutdown decay heat removal and containment cooling).
The consequences associated with these events were estimated by considering the following scenario. While at full power, a malfunction in the plant required the plant protection system to automatically shut down the plant. However, a demineralizer problem caused the loss of function of one of the safety systems which could be affected by demineralizers. Other safety systems were assumed to fail with probabilities as defined in the Oconee-3 and Grand Gulf-1 PRAs leading to a core-melt with containment failure. Since this event could result in a loss of core cooling, containment cooling, or containment spray, it was considered to be bounded by the PWR-2 and BWR-2 release categories which have estimated dose consequences of 4.8 x 108 and 7.1 x 10 5 man-rem / event, respectively.The transient-related accidents T2 s for BWRs and T3 for PWRs were expected to result in BWR release categories 1,2,3, and 4, and in PWR release categories 3, 5 and 7, respectively.*d l To estimate the reduction in risk associated with the elimination of demineralizer failures, two ,
calculations were involved: (1) the additional probability of reaching a core-melt due to 1 12/31/98 3.71-4 NUREG-0933
R: vision 2 O domineralizer failure which rendered a safety injechon system inoperable; and (2) the reduction in core-melt frequency resulting from a reduction in transient-induced scrams. The first was done by assuming that the effect of domineralizer failure contributed directly to the probability of core-melt by addag drectly to the failure probability of those systems that can be affected by
- domineralizer failures. This contribubon was calculated by examining the dominant accident sequences for PWRs and BWRs (using the Oconee 3 and Grand Gulf-1 PRAs as representative of these plants) and, for those sequences that involve systems whose performance could by affected by domineralizer problems, adding to that system an annual unavailability of (2 x 104 ) for PWRs and (1.4 x 10 4) for BWRs. This would then represent the incremental increase in the frequency of a core-melt accident for a plant. The values calculated for these increases in frequency were 6.4 x 104/RY and 8.8 x 10 4/RY for PWRs and BWRs, respectively. The transient reductions were based upon the frequency reduction values given prevo' usly. The transient reductions resulted in a reduction in core-melt accident frequency of 1 x 104/RY for PWRs and 8 x 10*/RY for BWRs. The risk reduction associated with resolution of this issue was calculated below.
PWRs: System Failure Risk Reduction = (6.4 x 10 4/RY)(4.8 x 10 man-rem 8
/ event)(30 years)
= 9.2 man-rem / reactor Transient Risk Reduction PWR-3 = (0.5)(9.9 x 104 /RY)(5.4 x 10e man-rem / event)(30 years) l
= 8 x 104man-rem / reactor PWR-5 = (0.0073)(9.9 x 104/RY)(1 x 10 man-rem 8
/ event)(30 years) l 4
= 2.2 x 10 man-rem / reactor PWR-7 = (0.5)(9.9 x 104 /RY)(2.3 x 10 5man-rem / event)(30 years)
= 3.4 x 10 4man-rem / reactor Total PWR dose reduction = 9.3 man-rem / reactor BWRs: System Failure l
Risk Reduction = (8.8 x 10 4/RY)(7.1 x 10 man-rem 8
/ event)(30 years)
= 15.1 man-rem / reactor Transient Risk Reduction BWR-1 = (0.01)(1.4 x 104/RY)(5.4 x 10 8man-rem / event)(30 years)
= 0.022 man-rem / reactor BWR-2 = (1.0)(7.8 x 10 4/RY)(7.1 x 10e man-rem / event)(30 years)
= 16.6 man-rem / reactor BWR-3 = (0.5)(2 x 10*/RY)(5.1 x 10 8man-rem / event)(30 years)
= 0.15 man-rem / reactor
(
12/31/98 3.71-5 NUREG-0933
Revision 2 B W R-4 = (0.5)(2 x 104/RY)(6.1 x 10 5man-rem / event)(30 years)
= 0.018 man-rem / reactor Total BWR dose reduction = 32 man-rem / reactor -
In addition, since hardware fixes were assumed to be part of the solution of this issue, the occupational dose associated with the installation of these fixes were considenad. The addition of 6 strainers per plant on the outlet of demineralizers was assumed as the hadware fix.
The occupational dose received from the installation of demineralizer strainers was estimated as follows: (1) it was assumed that the installation of each strainer favolved 40 man-hours of labor in a radiation zone; and (2) from Chapter 12 of the Oconee-3 and Grand Gulf-i FSARs, the dose rate in the areas where demineralizers are present was approximately 100 millirem /hr when the plant is shutdown. Therefore, the occupational dose received from the installation of 6 outlet strainers was (40 man-hrs)(6)(0.1 rem /hr)=24 man-rem / reactor.
Since this occupational dose was less than the risk reduction dose consequences, it appeared that there was some benefit to implementing such fixes. The impact of additional strainers on increased occupational dose due to maintenance was assumed to be ne.gligible.
Cost Estimate Industry Cost: The cost associated with resolution of this issue involve hardware additions (demineralizer outlet strainers) to mitigate the consequences of demineralizer failures, procedure changes, and additional operator training. Hardware fixes were estimated to cost $600,000 based on the addition of 6 outlet strainers / plant. Procedural changes were estimated to cost $12,000 assuming 1 man-month / plant. Based on 1 man-week /RY, additional operator training was estimated to cost ($3,000/RY)(30 years)or $90,000. Thus, the total industry cost was estimated to be $700,000. It was assumed that all of the fixes could be done during normally scheduled downtime; therefore, the cost of replacement power was not a factor.
Additional maintenance costs to monitor implementation were assumed to be negligible. However, it was also possible that a reduction in domineralizer problems would also reduce undesired plant shutdowns and thus save licensees the cost of replacement power. From the LER search, it was determined that, of the 15 events reported involving demineralizers,2 caused plant shutdowns to correct the problem. It was assumed that half of these could be avoided by the better training procedures and mitigation effects of demineralizer outlet filters. Therefore, based on the LER data, a plant will avoid [(1)(30 years)/(75)(2.5 years)]=0.16 shutdown / plant due to demineralizer problems over its life. This resulted in a cost savings to each plant of (0.16 shutdown)($500,000/ shutdown)=580,000/ plant over its life. (Each shutdown was assumed to last 1 day at a cost of $500,000/ day.) Therefore, the total cost / plant to resolve this issue was estimated to be $(700,000 - 80,000) or $620,000.
NRC Cost: NRC costs were negligible.
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12/31/98 3.71-6 NUREG-0933 l
Rsvision 2 Value/ impact Assessment Based on estimated public risk reductions of 9.3 man-rem / reactor and 32 man-rem / reactor for PWR and BWRs, respectively, and a cost of $0.62M/ reactor for a possible solution, the value/ impact scores were given by:
(1) PWRs: S = 9.3 man-rem / reactor
$0.62M/ reactor
< 15 man-rem /SM (2) BWRs- S = 32 man-rem / reactor
$0.62M/ reactor
< 52 man-rem /$M Other Considerations (1) The assumptions used in this evaluation regarding frequency and consequence estimates were conservative because the estimates of frequencies of transients and failures in BWRs were high and the bounding of non-transient accidents by BWR-2 and PWR-2 )
releases resulted in high public dose estimates. Therefore, the value/ impact scores were J considered to be high estimates.
J i
(2) Many domineralizer failures can and are detected (via water chemistry, etc.) prior to their
( affecting other equipment.
(3) Generally, a demineralizer failure affects only one system and this is not enough to prevent i a plant from performing its safety functions. In the one case at TMI-2 where more than one j system was affected,"' the plant was in the pre-operational testing phase, prior to j certification that the plant condition (equipment and procedures) was suitable for power l operation.
l l
At the time of this evaluation, fixes following the TMI-2 failure appeared to have reduced (4) the frequency of occurrences.
CONCLUSION Based on the above value/ impact scores, the issue was given a low priority ranking (see Appendix C) in February 1990. Further prioritization, using the conversion factor of $2,000/ man-rem approvedises by the Commission in September 1995, resulted in impact /value ratios (R) of
$66,666/ man-rem and $19,375/ man-rem for PWRs and BWRs, respectively, which placed the issue in the DROP category.
REFERENCES
- 64. NUREG/CR-2800, " Guidelines for Nuclear Power Plant Safety issue Prioritization Information Development," U.S. Nuclear Regulatory Commission, February 1983, 12/31/98 3.71-7 NUREG-0933
l l Revision 2 (Supplement 1) May 1983, (Supplement 2) December 1983, (Supplement 3) September
- 1985, (Supplement 4) July 1986, (Supplement 5) July 1996.
l 516. Memorandum for W. Johnston and L. Rubenstein from T. Speis, " Failure of Resin
! Demineralizer Systems and Their Effects on Nuclear Power Plant Safety," August 6,1982.
l l 1172. Letter to R. Engelken (NRC) from H. Ray (Southem Califomia Edison Company), " Docket l No. 50-361, Licensee Event Report, Numbers82-002 and 82-003, San Onofre Nuclear Generating Station, Unit 2," March 30,1982.
1173. Letter to R. Haynes (NRC) from C. Mathis (Boston Edison Company), " Docket No. 50-293,
- License DPR-35," September 15,1982.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
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l lSSUE 80: PIPE BREAK EFFECTS ON CONTROL ROD DRIVE HYDRAULIC LINES IN THE DRYWELLS OF BWR MARK I AND ll CONTAINMENTS i
! DESCRIPTION l
Historical Backaround i
l During some BWR operating license reviews, the ACRS posed questions concoming the likelihood l and effects of a LOCA which could cause interactions with the CRD hydraulic lines in such a way l as to prevent rod insertion, creating the potential for reenticality when the core is reflooded."7The l staff investigated this potential problem and concluded that the existing SRP" criteria were -
adequate to assure integrity of the CRD hydraulic lines."' These criteria assume conservative failure stresses and break locations in coolant pipes and require examination of the effects of pipe whip and jet impingement on essential safety components (including the CRD hydraulic lines) for approximately 100 breaks.
l The ACRS discussed this conclusion with the staff during its 273rd meeting on January 6,1983, j but remained concemed about MARK I and ll containments, which are smaller and more congested than the MARK lli containments upon which the staff's analysis was concentrated."'
- Tho, the issue remained open for the MARK I and ll containments.
l Safety Sionificance l
l Recriticality during the course of an accident has no direct effect on the health and safety of the l public. However, failure to insert a significant number of control rods could pose two separate l safety problems. First, when the core is reflooded by cold emergency core cooling water, the l reactor will undergo a cold water reactivity transient if the core is not subcritical. The cold water can insert considerable positive reactivity, which means that portions of the core where control rods failed to insert can retum to a significant power level and may even overshoot to power levels l considerably higher than those experienced during normal operation. Secondly, the recirculation phase of emergency core cooling is sized to carry away decay heat. If fission heat is not shut off, the ECCS may not be sufficient to remove this extra energy, resulting in coolant boil-off, l containment failure, and core-melt.
Possible Solution A possible solution was to install some type of guard structure at points where the CRD hydraulic lines are vulnerable.
PRIORITY DETERMINATION Frecuency/Conseauence Estimate t
A BWR control rod is scrammed by applying pressure from an accumulator on the reactor vessel to the volume below the CRD piston and venting the volume above the piston to the scram discharge volume which is near atmospheric pressure. lf the insert line is either blocked or broken, 12/31/98 3.80-1 NUREG-0933 L
Rsvision 2 a bali check valve built into the CRD will admit reactor water to the volume under the piston. Thus, the insert line is necessary for scram only when the reactor pressure is low, e.g., during reactor startup.
Breaking the withdraw line will open the volume above the piston to atmospheric pressure and thus cause (not prevent) a scram. The only way to prevent a scram by mechanical damage to the CRD lines is to crimp the withdraw line shut. Breaking or crimping an insert line will prevent a scram only at low reactor pressure at which time the high energy coolant lines, which are to provide the crimping force, are also at k,w pressure and the reactor is also at very low power. CRD hydraulic lines originate at the CRD flanges. They are routed up from these flanges, curve 90',
and travel horizontally between the CRD housings. The lines are divided into two banks which exit the area under the vesselin two penetrations of the reactor support pedestal placed 180' apart.
After traversing the drywell area, the lines exit the containment via two containment penetrations and are then routed to the two banks of hydraulic control units.
In the area under the reactor vessel, there is only one high-energy line, a two-inch lower vessel head drain which is one input to the RWCU system. This line is not considered a significant hazard to the CRD lines for several reasons:
(1) The CRD lines are routed below a set of I-beams. (The CRD housing support is attached to hanger rods which descend from these beams). Thus, the CRD lines are well shielded from the drain line which is above the I-beams.
(2) Breakage of this drain line would be a small LOCA. Normally, the reactor would continue to run, with the only problems being loss of some RWCU flow and a steam-feed flow mismatch. The reactor would not scram until the drywell pressure rose to the scram setpoint. This does not isolate the reactor and main feedwater would continue.
(3) Even if main feedwaterwere lost, HPCI has the capacity to handle a 2-inch break (double-ended) with enough extra flow to supply about 40 bundles operating at average power.
(4) If HPCI is insufficient, ADS can vent about 38% of rated steam flow. Thus, quite a few rods would have to fail before ADS would be insufficient.
In the area between the reactor support pedestal and the drywell wall, the situation is different.
Here, the CRD lines pass near the reactor coolant piping and headers. The recirculation piping exits the vessel from two nozzles located nearthe bottom of the annulus and travels down through i the general area where the CRD lines are located to the recirculation pumps which are at a still lower elevation. Flow from the pumps travels through two pipes up to two semi-circular manifolds, which again are in the general area of the CRD lines. Each manifold then supplies driving flow to the jet pumps through a series of risers, one riser for every two jet pumps. The CRD hydraulic lines cross this area under the manifolds. The usual practice is to route each bank in an array of six horizontal rows of hydraulic lines.
The rest of the vessel piping (feedwater, etc.) is located considerably higher in the drywell. This other piping is not considered a significant hazard because of its distance from the CRD lines and the rather narrow annular gap through which any missiles or jets would have to pass. Thus, concentration was placed on the recirculation piping. Given a break in the recirculation system, O
12/31/98 3.80-2 NUREG-0933
Rsvision 2 an estimate of the probability of crimping or sealing a line completely shut was needed. The best that could be done was to attempt to bound the true probability.
It should be noted that the outcome of the accident under consideration is relatively insensitive to scram timing, so long as the rods are successfully inserted. A small LOCA will not cause a reactor scram until esther the water level drops to the scram setpoint or the drywell pressure rises to its setpoint. A large LOCA will depressurize the reactor and stop the fission chain reaction by high voiding of the moderator and the rods need not be inserted until the blowdown is complete.
Thus, the interest was in complete rather than partial obstruchon of the CRD lines, since partial obstruchon would only delay, not prevent, the scram.
Credit was taken for the possibility that non-inserted rods might be widely dispersed and thus not lead to recnticality. This was not as conservative as it first appeared. The CRD lines are not necessarily routed in such a manner as to disperse the drives they control, and blockage of adjacent lines may well inhibit scram in adjacent CRDs. Finally, insert and withdrawal lines were considered equally, since a large LOCA could depressurize the reactor before a rod with a crimped insert line is completely inserted. (This was in fact quite conservative.) The SLCS is normally capable of borating the moderator to 600 ppm of natural boron (referenced to cold water density) plus a 25% safety margin. This concentration would render the core up to 5% subcritical with all control rods fully removed at cold, xenon-free conditions at the most reactive point in core life. However, following a large LOCA, the SLCS effectiveness is reduced by the diluting effect of the suppression pool, which normally contains about 7% vesselinventories. Thus, the SLCS can realistically borate only to about 88 ppm. Based on calculations done forATWS, this would reduce power to roughly 75% of rated (with no rod insertion). It would not shut the reactor down.
Several effects help bring power down." First, existing xenon, augmented by xenon increase, holds power down for roughly 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the accident. Second, the recirculation pumps are no longer providing forced flow through the core, which tends to bring power down by allowing more voiding. Finally, unless the pipe break area is small enough to limit leakage to less than ECCS injection, water level will drop to % of the core height, which will greatly reduce moderator density in the upper third of the core. Nevertheless, the core must eventually be brought to cold shutdown by means of the SLCS. Over the long term, this would not be difficult, since more sodium pentaborate mixture could be added to the SLCS so long as the secondary containment remained accessible. It was assumed that the SLCS would be ultimately used to render the core sub-critical over a span of several days.
An examination of the sequence of events was performed. A CRD line can be crimped completely shut by the impact of a missile or energetic fluid jet, if the circumstances are right. First, the line could be caught between the impacting mass and an opposing surface and be flattened shut.
Second, if the impact occurred near a point of support for the line, the line could be severed and the stub bent over at a right angle. The line might then be flattened shut at the point of minimum radius of the bend. Finally, a sufficiently energetic impact theoretically could seal the line with only the inertia of the opposite side of the tube providing an opposing force.
Pioe Whio: In this scenario, a recirculation line breaks in such a manner that the whipping pipe strikes one bank of CRD hydraulic lines. It was assumed that the impact would block the entire bank, either by flattening the lines or by breaking the lines and bending them sharply.
0 12/31/98 3.80-3 NUREG-0933
Rtvision 2 l
l The CRD lines are located under the two semicircular recirculation manifolds. Thus, they are vulnerable to pipe whip primarily from the manifolds but also from the vertical recirculation pipes ,
carrying flow to and from the recirculation pumps.
The frequency of a large break somewhere in the recirculation system was generally estimated l to be 10d/RY. This number was modified to account for several spatial effects: I Break Location - Pipe whip restraints are located every 30* around the split manifold, except for two 60* intervals located at the ends of the two semicircles. To be a hazard to ;
the CRD lines, the pipe break must be in the interval which spans the CRD lines. i Therefore, a factor of 0.-05 was used, which was the length of pipe in one 60* interval divided by the total length of recirculation piping. {j Vertical Piping - The CRD lines may be routed close enough to a recirculation pump suction or discharge line to be affected by breaks in these lines. This was conservatively accounted for by introducing a factor of two.
Direction of Whip - The pipe break is as likely to cause the pipe to move sideways or away from the CRD lines as toward them. For this, a factor of 0.25 was assumed.
Two CRD Line Banks - To account for the fact that there are two sets of lines 180* apart, a factor of two was used.
- Extent of Whip - Pipes are not expected to whip more than one pipe diameter at the maximum. In addition, although CRD line routing is done in the field, the fact that insulation has to be installed on recirculation lines gives assurance of at least a foot or so of clearance between the recirculation piping and the CRD lines. The probability that the pipe will whip far enough to hit the CRD lines was assumed to be 0.1.
Multiplying the above numbers, the frequency of this scenario was estimated to be 5 x 10 # l event /RY.
When the core is reflooded, about half the core will undergo a cold water reactivity transient.
Cladding failure is not a concem here, since it was assumed that every fuel rod in the core would be perforated. Instead, it was necessary to examine the effect of the transient on the fuel matrix itself. The rod drop accident (licensing basis) inserts -1.3% AK in about 0.6 seconds. Reflooding the reactor will insert about 8% AK, when filled with cold water (with xenon present). However, it takes about 30 seconds to refil; the vessel from the bottom to the tope of the core. Thus, the reactivity insertion rate is about a factor of eight below that of the rod drop accident and the rod drop accident is more limiting.
The licensing basis calculations for a control rod drop accident predict a peak fuel rod enthalpy of about 220 calories / gram when the inserted reactivity is 1.3% AK.* However, the rod drop accident initial conditions include an enthalpy of 20 calories / gram (540
- F), whereas the cold water reflood transient under consideration here starts with fuel enthalpies as high as 85 calories / gram (2200*F). Thus, since the AK in the reflood transient is less than the AH in the rod drop accident, the rod drop accident AH can be added to the initial enthalpy of the reflood transient and it can be concluded that the peak enthalpy achieved in the reflood transient will be less than 285 calories / gram.
12/31/98 3.80-4 NUREG-0933 l
l l
Rsvision 2 p This peak enthalpy corresponds to a point about 20% into the interval between onset of fuel Q melting (269.4 calories / gram) and complete melting (336.8 calories / gram). Therefore, we will bound the radiological effects of the reflood reactivity transient by assuming that the radioactive .
release due to this transient is at most 20% of a core-melt reWase in those fuel bundles where the !
associated control rods do not scram. Since only half of the control rods fail to scram, the release is bounded by one-half of 20%, or 10% of a full core-melt.
It should be noted that this was a highly conservative estimate. First, the assumed reactivity l insertion rate was about a factor of eight higher than realistic. Second, the AH calculations do not l take credit for moderator feedback; more realistic calculations have predicted AH values on the order of 100 calories / gram." Finally, the duration of the hypothetical partially-molten state is very brief. Thus, it was very doubtful that the reflood reactivity transient would in reality result in any fuel melting.
After core reflood, fission power will continue at a low rate in the core." The recirculation phase of ECCS may not be sufficient to remove this energy and the containment will then fail due to overpressure. Thus, the radioactivity released by the reactivity excursion will escape to the atmosphere in the manner of a BWR-2 release but with one tenth its magnitude, in addition, the gap activity from the fuel which did not undergo a reactivity transient, and which would otherwise have been trapped within containment, will be released. There is no BWR release category for this situation, but the consequences of this release can be bounded by those of a PWR-8 release.
With the containment open and steam escaping to the atmosphere, the suppression pool will eventually be depleted of water. If the standby coolant supply system fails (forwhich a probability
,C ' of 0.015 was assumed), there will be no liquid water supply for the ECCS and the entire core will d melt. For this, a full BWR-2 release was assumed. The priority parameters for this scenario were calculated as follows:
Public Risk < 0.45 man-rem /RY Core-melt Frequency < 7.5 x 104/RY Fluid Jets: A fluid jet driven by a 1000 psi pressure cannot directly flatten a tube which contains 1000 psi fluid. However, impingement of such a jet will cause severe vibration of CRD lines. The lines may flatten as they repeatedly hit each other or hit any other structures (e.g., supports) which are within their vibrational amplitude. In reality, one would expect these lines to be more likely to rupture than to flatten. Nevertheless, flattening is possible and was assumed here.
The hazaM to the CRD lines depends on their arrangement and distance from the pipe break. A typical practice in routing CRD hydraulic lines is to arrange the lines in six horirontal rows. In such an arrangement, lines located within the matrix will be shielded from some or uic force of an extemal fluid jet. Thus, if the CRD lines are located close to the pipe break, the jet will be concentrated and might penetrate into the CRD lines matrix with sufficient force to cause vibratory flattening. Conversely, if the lines are located at some distance from the break, the jet will be more diffuse and less likely to penetrate past the first row of lines but will also, because of this same dispersion, impinge on a wider area and thus affect more of the outside row.
It was assumed that the break (and the jet) are 22 inches in diameter, which is the diameter of the recirculation manifold. To cover both the near and far cases, it was assumed that the entire top row of lines is flattened and, in addition, a 22-inch (tranverse) span is flattened to a depth of all 12/31/98 3.80-5 NUREG-0933
Revision 2 six rows. For a 1000 MWe plant with 185 control rods, this meant that 43 rods will fail to insert; this corresponds to 23% of the core.
The above was based on the assumption that the CRD lines are arranged in a matrix 6 rows high and with a pitch of two inches. In such a case, the matrix would be 62 inches wide. The probability of a break in the recirculation manifold being above this span is about 1.7%.
The event tree is similar to that of a pipe whip: a recirculation line breaks (104/RY), the break is above the CRD lines (0.017), and the fluid jet is directed downward (0.25). The result is that 23%
of the core experiences a reactivity transient and continued steam production eventually ruptures the containment (20% of a BWR-2 release in the uncontrolled fuel plus a PWR-8 release). If the standby coolant supply system fails (0.015), the ECCS will eventually run out of water and the entire core will melt (BWR-2 release). However, priority parameters calculated from these figures must be doubled to account for the presence of two banks of CRD lines and doubled again to account for the presence of vertical recirculation piping. The results were:
Public Risk < 0.86 man-rem /RY Core-melt Frequency < 2.6 x 104/RY Pipe Fraoments: If a recirculation line " breaks" by opening a weld, relatively few fragments will be produced. However, if the pipe fails because a crack propagates in a circle and closed on itself, pipe fragments could be a significant hazard.
The hazard from pipe fragments is different from that of a fluid jet. First, because a solid object can concentrate its impact in a small area, it can block a CRD line directly by denting the line.
Second, solid objects will retain this full impact over a great distance, as opposed to the diffusion of a fluid jet. On the other hand, a solid object cannot flatten a CRD line within the matrix without breaking the lines in the rows above.
It was assumed that a section of recirculation manifold with a span equal to a pipe diameter (22 inches) suddenly breaks into fragments. To estimate the number of CRD lines which could be dented shut, it was further assumed that the lines are located immediately adjacent to the manifold. The pipe fragments, which at close range will act like one solid mass, will then impact a 22-inch span of the top row of CRD lines. Since these lines may well be all withdrawal lines, it was assumed that eleven control rods will fail to insert.
The accident sequence starts out with a large LOCA (10"/RY). The break must be over the CRD lines (0.017) and pointed down (0.25). The result is that 6% of the core retums to criticality after a mild reactivity excursion (20% of a BWR-2 release per fuel bundle) and the containment eventually is overpressurized (75,000 man-rem from gap activity). If the standby coolant supply system fails (0.015), the entire core will melt (BWR-2 release). Again, the resultant figures must be multiplied by four to account for vertical pipes and two CRD banks. The results were:
Public Risk < 0.45 man-rem /RY Core-melt Frequency < 2.6 x 104 /RY ;
i At the time of this evaluation, there were 35 plants with either a MARK I or 11 containment l and, based on a 40-year life, there were approximately 1,180 RY of operation left. Based on this data, the following priority parameters were calculated:
12/31/98 3.80-6 NUREG-0933 l l
Ravision 2 Man-rem / Reactor < 60 Man-rem, Total < 2,100 Core-melt /RY < 6 x 10*
Core-melt / year < 2 x 10 4 Cost Estimate Industry Cost The cost of the fix was estimated to be approximately $2M/ reactor. This was an order of magnitude midway between $20M, the cost of extensive torus modifications, and
$200,000, which could easily be used up by the paperwork involved in a backfit. Thus, the cost to a licensee was within an order of magnitude of $2M.
NRC Cost: The NRC cost was estimated to be on the order of one man-year or $100,000.
Total Cost: The total industry and NRC cost associated with the possible solution was estimated to be $(2+ 0.1)M or $2.1M.
Value/ impact Assessment Based on an estimated public risk reduction of 60 man-rem / reactor and a cost of $2.1M/ reactor for a possible solution, the value/ impact score was given by:
S = 60 man-rem / reactor
$2.1M/ reactor
= 29 man-rem /$M 1
CONCLUSION Based on the above value/ impact score, the issue was given a low priority ranking (see Appendix C) in January 1984. In NUREG/CR-5382,'" it was concluded that consideration of a 20-year license renewal period could change the ranking of the issue to medium priority. Further prioritization, using the conversion factor of $2,000/ man-rem approved'"' by the Commission in September 1995, resulted in an impact /value ratio (R) of $33,333/ man-rem which placed the issue in the DROP category.
REFERENCES ;
11, NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," U.S. Nuclear Regulatory Commission, (1st Edition) November 1975, (2nd Edition) March 1980, (3rd Edition) July 1981.
537. Memorandum for W. Dircks from R. Fraley, August 18,1982.
538. Memorandum for R. Fraley from H. Denton, "ACRS Inquiry on Pipe Break Effects on CRD Hydraulic Lines," October 29,1982.
O 12/31/98 3.80-7 NUREG-0933
1 I
Revision 2 l
539. Letter to W. Dircks from J. Ebersole, "ACRS Comments Regarding Potential Pipe Break (
l Effects on Control Rod Drive Hydraulic Lines in the Drywells of BWR Mark I and 11 Containments," March 16,1983.
540. BNL-NUREG-28109, " Thermal-Hydraulic Effects on Center Rod Drop Accidents in a Boiling Water Reactor," Brookhaven National Laboratory, July 1980. {
541. Memorandum for B. Sheron from C. Berlinger, "ACRS Request for Information Related to LOCA Effects on CRD Hydraulic Lines," October 19,1982.
1563. NUREG/CR-5382, " Screening of Generic Safety issues for License Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991.
1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Conceming issuance of Regulatory {
Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the !
Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
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l l
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1 12/31/98 3.80-8 NUREG-0933 l
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R: vision 2 O
V ISSUE 90: TECHNICAL SPECIFICATIONS FOR ANTICIPATORY TRIPS DESCRIPTIOl!
Historical Backaround Reactor protection systems (RPS) or " scram" systems are tripped by many diverse signals. The purposes of these various signals can be broadly divided into three classes: protection of the reactor core (e.g., overpower signals); protection of major components (e.g., vessel overpressurization signals); and anticipatory trips. The purpose of an anticipatory trip signal is to scram the reactor at the very beginning of a transient and thus minimize the degree of upset of the plant and avoid actuation of engineered safety features.
By definition, credit is not taken for an anticipatory trip in a plant's safety analyses, even to satisfy a single failure criterion. (Conversely, if a transient analysis calculation upon which TS are based takes credit for early reactor scram due to an " anticipatory" trip, the trip can no longer be considered " anticipatory.") Originally, it was AEC (and then NRC) regulatory policy to consider such trips to be installed for the licensees' convenience rather than forlicensing purposes.e Thus, no TS requirements were placed on these trips. At the time the STS was introduced, this policy was changed and a_II, trips in the RPS were included in the STS. However, plants licensed prior to the advent of STS were not backfitted with TS on anticipatory trips. In addition, post-STS reviews
,T of custom TS done after the STS were introduced did not require the inclusion of specifications
) on anticipatory trips.
This issue originated when Region ll noted the anomaly and found that licensees were often performing little or no maintenance on these trips in the absence of TS requirements.' With no mention of these trips in the TS, Region 11 could take little action even in cases where inspectors had reason to doubt the operability of these trips. DSI/NRR recommended that the issue be included in the broader study involving the overall adequacy of the TS. However, at the time this issue was evaluated, RSB/DSI had not defined a scope or schedule for a systematic study of all TS.
Safety Sianificance The safety significance identified' was that, "because anticipatory trips are a part of the protection system, a failure or maintenance action in the anticipatory trip could cause other trips relied on in the accident analysis to be degraded below an acceptable level." The design of the RPS, however, leans strongly towards a fail-safe direct;on, i.e., failure of any channel may cause an inadvertent reactor scrart. but should never prevent a trip of another channel from scramming the reactor. Questions of this nature are valid (e.g., can the W scram-on-turbine-trip interact with other channels via the P-7 interlock?), but the DL/NRR memorandum'3 did not provide any specific concems. Moreover, ICSB/DSI/NRR mentioned none in its examination of this issue,' '
and the fault tree analysis of WASH-1400'8 (Appendix II, S5.2) found no such interaction, in the absence of specific concerns, iwas concluded that this part of the issue was better treated under the auspices of the ATWS program and was not taken into consideration in this evaluation.
n v
12/31/98 3.90-1 NUREG-0933
._ ________________.m_____
Rsvision 2 The second area of potential safety significance was a plant's response to a transient. Since i anticipatory trips reduce the degree of plant upset, they also (in principle) reduce the frequency l of challenges to engineered safety features, and thus (again, in principle) reduce the frequency l of transient-initiated accidents.
Possible Solution The proposed solution was implicit in the definition of the issue: impose TS requirements on anticipatory trips. Such specifications would include: (1) limiting safety system settings (LSSS),
which provide setpoints; (2) limiting conditions for operation (LCO), which require equipment to be operable during appropriate operational modes; and (3) serveillance requirements (SR).
PRIORITY DETERMINATION {
1 Assumptions )
A search through some older TS uncovered the following anticipatory trips:
(1) PWR - High neutron flux, source range PWR - High neutron flux, intermediate range (2) PWR - Turbine trip (3) PWR - Low steam generator level coincident with steam-feed mismatch (4) BWR - High neutron flux, source range Because these trips are notable via their absence in the TS, there is no guarantee that this list is complete. Nevertheless, these anticipatory trips should be representative. There are other trips (e.g., PWR RCP breaker open) which have LCOs and SRs, but do not appear in the LSSS.
Historically, this is because it is difficult to define "setpoints" for such trips. This is not a safety but a licensing improvement (enforceability) aspect and will not be considered here. Normally, calculations of scram failure probabilities are done for each channel of the RPS, explicitly accounting for the various 1/2,2/3, and 2/4 logic matrices with estimates of common mode failure rates included. Using this data, the following simplified assumptions were made.
First, imposing TS on anticipatory trips does not affect the common mode failure rate of the RPS.
Thus, when the changes in failure probabilities are calculated, the common mode failures are subtracted out. Second, lack of maintenance of an anticipatory trip is a common mode of both trip channels associated with the anticipatory trip parameter, i.e., if one channel fails, the other is also quite likely to fail. In the calculations, it was assumed that the probability that a trip signal will fail to cause a scram (i.e., both channels failing) is 0.01/ demand on an anticipatory trip which is not in the TS. This assumption was based on judgment augmented by conversations with the senior inspector who originated the issue. All other trip parameters were assumed to have failure rates of 104/ demand, based on Appendix II,65.2 of WASH-1400. 8 Frecuency/Conseauence Estimate (1) PWR - Hiah Neutron Flux. Source and Intermediate Rance These trips are functional only during reactor startup. They are backed up by the low setpoint of the power range neutron flux channels. Usually, the source range monitor 12/31/98 3.90-2 NUREG-0933
p.
Ravision 2
- setpoint is set at 105counts /second (which is equivalent to roughly 0.01% of rated reactor power) and the intermediate range setpoint and power range low setpoint are both set at 25% of rated power. Thus, the source range is truly anticipatory in the sense of attempting to stop a transient early while the intennediate range backs up, but does not anticipate, the low power setpcint of the powerr range channels.
Rod Election: The first " transient" of interest is not an anticipated operational occurrence, but is considered an accident. A rod ejection is a reactivity excursion which is, if significant at all, too rapid for the anticipatory nature of the source range trip to make' much difference. Thus, the safety contribution comes from increased scram reliability, not early scram. The following assumptions were made: 10 reactor startups/RY78; two days of vulnerability /startup (based on judgment); and 104 rod ejections /RY (based on WASH-1400, Appendix 1, 64.3). This translates to 5.5 x 10-7 rod ejections /RY atlow power. The change in scram failure rate is (102 - 10d ) for the source and intermediate range trips d
multiplied by 10 for the low setpoint power range trip. Thus, the change in core-melt frequency was given by:
7 AF = (5.5 x 10 /RY)[(10-2)2 -(10")2](10 )
d
= 5.5 x 10-'5/RY The consequences are those of a partial core-melt (if all these trips fail) which was bounded by a PWR-5 release (core-melt with the containment not isolated). Using the assumption of a uniform population density of 340 persons / square-mile, a 50-mile radius, a central midwest plain meteorology, and no ingestion pathways, a PWR-5 release results 8
in 10 man-rem. Thus, the estimated risk reduction was given by:
\
8 AFR s (5.5 x 105/RY)(10 man-re@
s 5.5 x 104man-rem /RY.
Short Periods: Under certain conditions of core bumup and high xenon inventory, differential rod worth tends to concentrate in a relatively narrow vertical range in the core during startup. This effect is much more pronounced in a BWR core (see issue 6), but can also occur in PWRs. Should this occur, the reactor core will go suddenly from subcritical to supercritical with a rapid positive period (on the order of 10 seconds). Older plants do not have flux rate trips.
If the SRM trip fails and the operator does not terminate the transient manually (assume 10% chance), the reactor core will not be shut down until power reaches the 25%
intermediate and power range setpoints. Fuel failure could also occur due to pellet / cladding interaction (PCI) during the rapid power ascension, or due to DNB because of the highly axially peaked power shape. At the time this issue was first evaluated in August 1984, no such events had occurred at a PWR. IE Bulletin No.79-128 and IE Circular No. 77-0751isted 5 such events in BWRs as of May 31,1979. This corresponded to about 155 BWR-years of experience.
It was assumed that the PWR frequency was at most one-tenth of the BWR frequency, or 3 x 10'8 event /PWR-year. The consequences were also bounded by those of PWR-8 and PWR-9 releases which corresponded to mitigated large break LOCAs without and with O containment isolation (i.e., widespread cladding failure but no fuel melting). The WASH-U 12/31/98 3.90-3 NUREG-0933
- 1. . .
Rsvision 2 1400a assumption of containment isolation failure probability is 0.1. The risk associated with the short period scenario was given by: ,
AFR s (3 x 10 4event /RY)[(10 10 d) SRM trip failure / event] l x (0.1 operator failure / event) x [(120 man-rem / accident, containment isolated)
+ (0.1 isolation failure / accident)(7.5 x 10d man-rem / accident, containment not isolated)] l s 2.3 x 10-2 man-rem /RY. l Rod Bank Withdrawal Error This transient is characterized by a slower reactivity insertion rate than those of the transients discussed above. Thus, fuel failure is not likely to occur because of a high rate of power ascension at the beginning of the transient, but instead may occur due to DNB as the core comes into the power range, possibly with an adverse power distribution due to some rod banks remaining in tne core.
For this to happen, the source, intermediate, and power range trips must fail, in addition, the rod stop must fail. A failure rate of 0.1 (rather than 0.01) for the rod stop was assumed since it was associated with the intermediate range detectors. No credit was taken for operator action since the cause of the event was probably operator error. Again, as discussed in the short-period transient, the consequences were bounded by those of PWR-8 and PWR-9 releases, assuming a containment isolation failure probability of 0.1.
In WASH-1400, the frequency of PWR uncontrolled rod withdrawal transients was estimated to be 0.01/RY. It was assumed that half of these occur during startup maneuvers. The risk estimate was given by:
AFR s (0.01 rod withdrawal events /RY) x (0.5 percentage in startup) x (10 10" source range failure rate change) x (0.1 rod stop failure rate) x (10 10" intermediate range failure rate change) x (104low setpoint power range failure rate) x [(120 man-remd/PWR-9 release) + (0.1 containment failure rate) x (7.5 x 10 man-rem /PWR-8 release)]
s 4 x 104man-rem /RY.
For this transient to progress to core-melt, the high pressurizer pressure, high pressurizer water level, overtemperature and overpower AT, and several other trips must fail.
However, the DNB event frequency above is already down to about 5 x 1012. Thus, even l if no credit was taken for these additional trips and the core-melt resulted in the worst case consequences (5.4 x 108 man-rem from a PWR-1 release, where the core-melt causes a steam explosion which ruptures both the reactor vessel and the containment), the resulting public risk would be only 3 x 104man-rem /RY.
Boron Dilution: This transient is caused by a CVCS malfunction which dilutes soluble boron in the reactor moderator. The reactivity insertion rate is very sicw, on the order of 10 4
/second at the start and diminishing asymptotically to zero as the moderator becomes more dilute. Thus, the transient is also very slow, giving the operator as much as an hour or more to take action for a dilution event during startup. Because the power increase is slow, fuel failures due to PCI are not expected.
12/31/98 3.90-4 NUREG-0933
Rsvision 2 For a PWR core at BOC conditions, there is insufficient reactivity worth in the control rods to maintain the core subentical with no soluble boron in the moderator. Thus, a reactor scram does not permanently terminate the transient; operator action is necessary to stop the dilution and re-borate the moderator. However, a reactor scram does give the operator more time to respond. In EPRI NP-801,"' the frequency of boron dilution events was estimated to be 0.03 event /RY. Again, it was assumed that almost half of these events occur during startup.
As the event progresses, the operator (for whom credit was given for this slow transient) must fail to observe the transient and take no action (assume probability s 0.10). The source range trip must fail (0.01 - 0.0001), the intermediate range trip must fail (0.01 -
0.0001) and the low setpoint power range trip must fail (0.0001). At this point, the estimated change in frequency is reduced to 1.5 x 10'"/RY. Reactor powerincreases past l 25% and thermal energy is dumped via the main condenser steam dump, the ADVs, l and/or the steam generator safety valves, depending on plant conditions. Eventually, as i reactor power increases to a value too great to be dissipated by these means, trip signals on pressurizer high pressure, pressurizer high water level, steam generator low-low water level, turbine trip (which functions as a 50% power trip as the P-9 permissive is reached),
overtemperature AT, and several others may scram the reactor. (Fuel still has not been damaged.) However, even with no credit for these non-neutron-flux trips, a frequency of i 1.5 x 10-"/RY was estimated. Thus, this transient was not considered further.
(2) PWR - Turbine Trio A turbine trip, normally sensed as either two out of three low autostop oil pressure signals or four out of four turbine stop valves closed, causes a reactor scram when the plant is operating above a preset power level (e.g.,10%). If a turbine trip occurs and this scram i fails, steam pressure will rise in the secondary system. The atmospheric dump valves and steam generator safety valves will be available to limit the pressure rise, and the steam dump (which is usually in Ty mode during power operation) will open and dump steam directly to the condenser. However, before these altemate energy sinks become available, the primary system will experience a rapid heat up. Expansion of the primary coolant will force coolant into the pressurizer, compressing the steam bubble. Reactor scram signals will be generated by the high pressurizer pressure, over-temperature AT and high l pressurizer level signals, and the transient will "tum around." Pressurizer spray will also tum on to limit the primary pressure transient, but it is likely that the PORVs will open. l This evaluation was restricted to W and CE plants. Upgraded anticipatory reactor trips on turbine trips were required of B&W plants by TMI Action Plan item II.K.2(10) which was implemented under MPA F-28. The safety significance of this trip is two-fold: (1) the anticipatory trip increases the reliability of the entire RPS, thus decreasing the frequency of ATWS events; and (2) by preventing opening of a pressurizer PORV, the frequency of a small LOCA is also decreased. In EPRI NP-801,"' the following transient frequencies involving a turbine trip are listed:
Turbine Trip 1.48/RY Load Rejection 0.45/RY Loss of Condenser Vacuum 0.12/RY Loss of Circulating Water 0.07/RY Total: 2.12/RY 12/31/98 3.90-5 NUREG-0933
Rcvision 2 The last two initiators will also disable the steam dump and, on plants with turbine-driven i main feedwater pumps, cause a loss of feedwater. However, tripping of the main turbine is the first event to cause a reactor transient.
It was assumed that a PORV opens about half the time in these transients. Also, the probability that a PORV will fail to re-close was estimated to be 1% per actuation (WASH-1400,'8 Appendix V, S4.3.1). The S2 LOCA sequence is then a turbine trip transient (2.12/RY), failure of the anticipatory trip channels (102 - 10"), opening of a PORV (0.5), l failure of the PORV to re-close (0.01), and failure of the operator to correctly diagnose the l problem and close the PORV block valves (assumed to be 0.1). The change in S2 frequency was then 104/RY.
The scram reliability is increased by the diversity of an anticipatory trip. However, placing TS on the anticipatory trip does not affect the common mode failure rate (CM) of the RPS.
If the high pressurizer pressure, overtemperature AT, and high pressurizer level signals ,
have failure rates of 0.0001/ demand, and the imposition of TS reduces the turbine trip signal failure rate from 0.01 to 0.0001, the RPS failure rate is:
(0.0001)'(0.01) + CM without anticipatory trip TS l (0.0001)$(0.0001) + CM with anticipatory trip TS.
The change in RPS failure rate is 9.9 x 10-'5; the common mode contribution cancels out.
This is negligible compared with the S2 sequences, therefore, it was not considered further.
The public risk associated with the S2 sequences was obtained by normalizing the WASH-1400'8 results (where an S2 frequency of 10 4/RY was assumed) to a frequency of 10'5/RY (see WASH-1400'8 Table V, 3-14. The results are shown in Table 3.90-1.
Table 3.90-1 ,
Release Normalized Consequence AFR Category AS2 (man-rem) (Man-rem /RY)
Frequency /RY PWR-1 1.0 x 10 4 5.4 x 108 5.4 x 10
PWR-2 3.0 x 10 4 4.8 x 10 8 1.4 x 10 2 PWR-3 3.0 x 10 4 5.4 x 10 8 1.6 x 10-'
PWR-4 3.0 x 10* 2.7 x 10 8 8.1 x 10-8 PWR-5 3.0 x 10* 1.0 x 10 8 3.0 x 10'3 PWR-6 2.0 x 10 4 1.5 x 105 3.0 x 10 4 PWR-7 2.0 x 10 # 2.3 x 10 4.6 x 10" Total: 2.6 x 10 # 2.0 x 10-0 12/31/98 3.90-6 NUREG-0933
Revision 2 s
-(3)' PWR - Low Steam Generator Level Coincident with Steam-Feed Mismatch This anticipatory trip will scram the reactor on low steam generator water level coincident with steam flow greater than feedwater flow by a preset amount (usually 40% of rated). It is backed up by the low-low steam generator water level trip. The initiating event here is a total loss of feedwater event in any steam generator. Partial loss of feedwater events or total loss of feedwater flow at reduced power levels may not produce sufficient mismatch between steam and feedwater flow to actuate the anticipatory trip; such events are also slower and early scram is not as important.
If all feedwater pumps are lost, the secondary side water temperature will rise because of the loss of the relatively cool feedwater, the heat transfer across the steam generator tubes is reduced and the primary side heats up. Simultaneously, the secondary water level decreases. The anticipatory trip signal will occur, and then the low-low steam generator level trip. The increasing primary temperature and resultant coolant swell will force more coolant into the pressurizer, compressing the steam bubble and causing an increase in primary system pressure. Reactor trip signals on overtemperature AT, high pressurizer pressure, and high pressurizer level will occur if the reactor has not already been scrammed, and the PORVs may open to limit the pressurizer pressure. The AFW system l will also be initiated by the loss of main feedwater pumps or by low-low steam generator waterlevel. If the AFW system fails and the steam generator tubes uncover, primary side l temperature and pressure will rise more rapidly and the pressurizer safety valves will open.
However, the probability of this event is not greatly affected by reliability of the anticipatory i scram. Thus, it was not considered in this evaluation. !
. As in the turbine trip transient evaluated previously, the anticipatory trip decreases the probability of an ATWS event and also helps prevent a pressurizer PORV from opening, thus decreasing the frequency of a small LOCA. The transients that will cause a loss of feedwater were taken from EPRI NP-801"' and are listed in Table 3.90-2.
As in the turbine trip transient, it was assumed that a PORV opens half the time if the anticipatory trip fails and that the PORV fails to re-close 1% of the time. The S2 frequency is then 2.28 transients /RY multiplied by the change in probability of anticipatory trip failure (0.01 - 0.0001), the probability of PORV opening (0.5), the probability of failure of the PORV to re-close (0.01), and the probability of operator failure to close the block valve 4
(0.1). The result of 10 /RY is the same as the turbine trip case and thu's the risk figures are the same: 2.6 x 10 #core-melt /RY,0.2 man-rem /RY.
The change in the probability of RPS failure is given by the change in anticipatory trip failure (0.0099) multiplied by the non-common mode failure probabilities of the trips on low-low steam generator level, over-temperature AT, high pressurizer pressure, and high pressurizer level, each of which is 0.0001. The resulting change in ATWS frequency is on the order of 2.3 x 10as/RY which is negligible compared to the S2 LOCA considerations above.
-(4) BWR - Hiah Neutron Flux. Source Ranae.
As in the PWR case, BWR licensing basis transient calculations for startup events do not take credit for the source range monitor (SRM) and intermediate range monitor (IRM) trip 12/31/98 3.90-7 NUREG-0933
Rsvision 2 setpoints, but instead assume that the reactor is scrammed by the startup mode setpoint of the average power range monitor (APRM) system, usually 15% of rated power. Unlike the PWRs, the IRM scram setpoints are already in the TS; the SRM scram setpoints are not required (although the monitoring function of the SRM is addressed). Moreover, it is common (if not universal) practice to disable the SRM scram inputs with shorting links after the plant's initial core loading is complete. Thus, the SRM scram generally has a failure probability of 1.
Table 3.90-2 Loss of feedwater (one loop) 0.99/RY Loss of feedwater(allloops) 0.08/RY Feedwater instability (operator error) 0.66/RY Feedwater instability (mechanical problem) 0.50/RY Loss of one condensate pump 0.05/RY Loss of all condensate pumps 0.00/RY TOTAL: 2.28/RY However, the SRM scram, at its usual setpoint of 5 x 105counts /second, is generally not the first scram to occur during a startup transient or accident. The reason is that, in a BWR, the IRM rod block and scram setpoints are defined as percentages of full scale for each IRM range, and the IRM ranges cover five decades. The SRMs and IRMs must overlap. SRMs are interlocked such that they cannot be withdrawn unless the RMs are on Range 3 or above. If the IRMs are on Range 1 (and if they are not, a rod block on IRM Downscale will prevent rod withdrawal), the IRM scram will occur virtually simultaneously with or (more likely) prior to the SRM scram. Therefore, the SRM scram will not reduce plant upset;it will only somewhat increase the reliability of the RPS. The events of interest are the rod drop accident (RDA) and the short period transient. (Because of the individual rod pulls used in a BWR, there is no analog to the PWR rod bank withdrawal error.)
RDAs and probabilities are discussed in an RDA Statistical Analysis.7The basic sequence starts with 2 x 10' rod withdrawals /RY in the startup range. To get an RDA, a rod must disconnect (maximum 2 x 10d), become stuck (maximum 10-2), and become unstuck and drop at the appropriate time (maximum 6 x 104 ). This does not imply that the rod is out of sequence or will lead to high worth. This translates into 2.4 x 104 RDA/RY requiring a reactor scram. The maximum improvement the SRM scram channel can make is (1 -
0.0001)(0.0001)2 or 104. The AF involved is then 2.4 x 104' event /RY; this is a negligible frequency. Even if such an event ruptured both the vessel and containment and completely melted the entire core under the worst conditions (i.e., BWR-2 release), the maximum public risk would be 1.7 micro-man-rem /RY. ;
Short period events are more common. As mentioned earlier, IE Bulletin No.79-125 and IE Circular No.77-075 list 5 such events in 155 BWR-years, a frequency of 3.2 x 10-2/RY.
12/31/98 3.90-8 NUREG-0933
Rsvision 2 These events will happen with the IRM channels set on their first range and the SRM
'O scram, if functional, would not anticipate other scrams but instead would provide a backup to the IRM scram. Rod blocks are largely ineffective here since the high incremental rod worth is tied up in one 6-inch notch.
Historically, these events have occurred just at the point of criticality. Since the operator is using the period meters to detect criticality, a short period event is easily noticed and these events have generally been terminated by operator action, not by the RPS. If the operator does not intervene (assuming a probability of 0.1) and the IRM and APRM scrams 4
fail (probability = 10 ), the reactor core would ascend into the power range where the usual reactivity coefficients would tum the transient around. The only consequence would be j some cladding failure due to PCl. The consequences to the public can be bounded by l those of a licensing basis RDA in which 770 fuel rods fail. These consequences are )
0.007 man-rem / event. Thus, the net risk from short period events, even with no credit for 4 4 the SRM scram is, at.most, (3.2 x 10 /RY)(0.10)(10 )(0.00/ man-rem) = 2.2 x 10-' man-rem /RY. Again, this is negligible.
Based on the calculations in (1), (2), and (3) above, the core-melt frequency estimate was ((5.5 x 105) + (2.6 x 10-7) + (2.6 x 104)}/RY or 5.2 x 10~7/RY. The public risk reduction was estimated 4 4 4 to be [(5.5 x 10 ) + (2.3 x 10 ) + (4 x 10 ) + (2 x 10 ') + (0.2)] man-rem /RY or 0.42 man-rem /RY.
Approximately 20 PWRs would be affected by the proposed action. Action on BWRs was unlikely to be approved since the potential safety gain from the SRM trip was so small.) Assuming an average remaining life of 20 years for the affected plants, the total remaining operating life was 400 RY. Thus, the total public risk reduction associated with this issue was approximately 170
( man-rem.
Cost Estimate l
Industry Cost: TS on anticipatory trips would probably be similar to those in the PWR STS. This would involve the following for Source Range Neutron Flux: (1) channel checks every shift except l during power operation; (2) calibration every refueling outage; and (3) analog operational tests monthly and prior to startups. For Intermediate Range Neutron Flux, this would include: (1) channel checks every shift while in startup; (2) calibration every refueling outage; and (3) analog ,
operational test monthly and prior to startup. For steam generator low level / steam-feed mismatch this would inciude: (1) calibration every refueling outage; and (2) analog operational tests monthly.
For turbine trip, this would include trip actuation device tests prior to startup. It was assumed that there would be 10 startups/ year,2 months refueling outage every 18 months,5 days to go from cold shutdown to power,10 minutes for channel checks,4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibrations, and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for analog and trip device tests. Based on a cost of $100,000/ man-year, the industry cost was estimated to be $4,000/RY or $1.6M for the affected plants.
NRC Cost: It was assumed that 2 man-years of effort would be needed to develop and carry out an action plan for the issue, including developing CRGR packages, etc., and that monitoring licensee compliance would take 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> /RY of inspection time.
Total Cost: The total cost of implementing the possible solution to this issue was estimated to be
$98,000/ reactor or approximately $2M for all affected reactors.
12/31/98 3.90-9 NUREG-0933
Rsvision 2 Value/ impact Assessment Based on an estimated public risk reduction of 170 man-rem and a cost of $2M for a possible solution, the value/ impact score was given by:
S = 170 man-rem
$2M
= 85 man-rem /SM Other Considerations The above calculations did not include credit for averted cleanup costs to the licensee. It should be remembered that avoidance of PORV opening (and secondary side safety valve opening) is a major reason for installing anticipatory trips. Inclusion of averted cleanup costs as a credit against the cost to the licensee could significantly raise the priority score. Moreover, the occupational man-rem averted by preventing PORV opening (and possible rupture of the pressurizer relief tank rupture disc) might also be significant.
CONCLUSION Based on the low risk reducticn potential and low value/ impact score, this issue was given a low priority ranking (see Appendix C) in August 1984. In NUREG/CR-5382,'58 it was concluded that consideration of a 20-yearlicense renewal period did not change the priority of the issue. Further prioritization, using the conversion factor of $2,000/ man-rem approved 888 by the Commission in September 1995, resulted in an impact /value ratio (R) of $11,765 / man-rem which placed the issue in the DROP category.
REFERENCES
- 5. IE Circular No. 77-07, "Short Period During Reactor Startup," U.S. Nuclear Regulatory i Commission, April 15,1977.
i
- 6. IE Bulletin No. 79-12, "Short Period Scrams at BWR Facilities," U.S. Nuclear Regulatory Commission, May 31,1979.
- 7. Memorandum for D. Ross from H. Richings, "RDA Statistical Analysis," June 17,1975.
- 16. WASH-1400 (NUREG-75/014)," Reactor Safety Study, An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," U.S. Atomic Energy Commission, October 1975.
178. EPRI NP-801, "ATWS: A Reappraisal, Part lli, Frequency of Anticipated Transients,"
Electric Power Research Institute, July 1978.
630. Memorandum for W. Minners from F. Miraglia, " Proposed Generic issue -Technical Specifications for Anticipatory Trips," February 23,1984.
O 12/31/98 3.90-10 NUREG-0933
r Rsvision 2 C 631. Memorandum for F. Miraglia from W. Houston, " Task Interface Agreement Task No. 83-77
[
(TAC 40002, PA-157)," Novemoer 29,1983.
1563. NUREG/CR-5382, " Screening of Generic Safety Issues for Ucense Renewal Considerations," U.S. Nuclear Regulatory Commission, December 1991, 1889. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per 1 Person-Rem Conversion Factor, Response to SRM Conceming issuance of Regulatory
- Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the i i .Need for a Backfit Rule for Materials Ucensees (RES-950225) (WITS-9100294),"
September 18,1995.
12/31/98 3.90-11 NUREG-0933
Rsvision 1 O
ISSUE 92: FUEL CRUMBLING DURING LOCA DESCRIPTION ;
Historical Backaround Experiments conducted at several test facilities prior to 1984 showed that irradiated fuel can fragment (crumble) into small pieces during a LOCA. Some evaluation of this effect was made for '
NRC by EG&G.e22 Although it was concluded that temperature increases due to relocation of crumbled fuel would be smaller than those due to other processes that are treated conservatively in Appendix K, the question was raised whether this effect should be treated as a long-term generic safety issue.s22
)
Safety Sionificance During the course of a LOCA, the primary system pressure drops and the fuel rods heat up. As I the rods heat up, the zircaloy cladding experiences a series of phase changes. Thus, the strength of the cladding varies, and at a certain interval during the heatup, the intemal pressure within a fuel rod will cause the cladding to plastically deform and swell, a phenomenon normally referred to as " ballooning." By this time, the ceramic fuel pellets may be cracked into small pieces. As the cladding swells, the crumbled fuel core drops into and (partially) fills the ballooned region while '
still producing thermal energy from radioactive decay. Thus, as the fuel settles into a shorter, fatter
( stack, the local linear power density (kw/ft) increases, even though the total rod power remains constant.
At the time of the initial evaluation of this issue in July 1984, the existing ECCS performance analysis codes did not account for fuel settling into ballooned regions. Thus, the lack of inclusion
' of this effect was a non-conservatism; however, the EG&G studye22 concluded that known l conservatisms would more than offset this effect.
Possible Solution j The only known solution to this possible problem was to account for the fuel settling and increased kw/ft in the ECCS calculations. This would result in stricter limits on FoorMAPLHGR,which would make maneuvering more difficult and could result in a plant derate.
PRIORITY DETERMINATION Freauency Estimate This item was an issue only for a mitigated LOCA. Therefore, the frequencies of A and S LOCAs i
in WASH-1400 were added. S 2LOCAs were not included because, if they were mitigated at all, they would be so far from the regulatory pellet cladding temperature (PCT) limit of 2200*F that additional heat from fuel crumbling could be accommodated. The sum of the A and S frequencies 3
was 4 x 10d /RY.
O V
12/31/98 3.92-1 NUREG-0933
Rsvision 1 l
l Not all LOCAs are design basis LOCAs. For a design basis LOCA, it is necessary to have the worst break location, the worst break size, the core power distribution at the Fa (or MAPLHGR) limit, and the worst single failure of the ECCS, plus other conservatisms in initial conditions, system capacities and calculational modeling. The conservatisms in traditional LOCA analyses may well be sufficient to compensate for the effect of fuel crumbling, as was discussed in the EG&G study.e22 However, the opposite approach was taken and no credit for calculation conservatism was assumed. Instead, the initial conditions in a probabilistic manner were included.
The probability of a LOCA being a design basis LOCA is very small. However, the worst case is often the worst by only a small margin, i.e., the worst break size and location may be closely l followed by other break sizes in otherlocations. Thus, the probability of a near design basis LOCA is significant. Based primarily on judgment, it was assumed that there was at most roughly a 10%
probability of a LOCA approaching design basis conditions.
Consecuence Estimate I l
e22 The EG&G study discussed a PBF calculation that was somewhat conservative but indicated that peak cladding temperatures rose 46*F and peak centerline temperatures rose 790*F above ,
the nominal (no fuel relocation) case when circumferential strain was 44%. A companion j calculation, assuming 89% cladding strain, yielded a cladding AT of 406* and a centerline AT of )
2290*F. However,89% core-wide cladding strain is not realistic. According to NUREG-0630,83d I a uniform cladding strain of 70% corresponds to all pins swollen into a square shape and pressed I against each other with no space remaining to accomodate further swelling. The numbers associated with 44% cladding strain, which corresponded to about 78% channel blockage, were used for core-wide calculations, i.e., it was assumed that every fuel pin in the core would swell 44% throughou' its length. j in addition, at some point along each fuel rod, the cladding swells to the point of bursting, which relieves the intemal pressure and terminates the ballooning process. Thus, it was further assumed that a one-foot section of each fuel rod (i.e., about 10% of the length of every fuel rod in the core) would swell to 89% cladding strain.
The rise in temperature was the main concem. Because the degree of ballooning is a function of how the cladding passes through its various phases, rather than only a function of its peak temperature, the increased temperature was not expected to increase the amount of ballooning.
Consequently, fuel crumbling and settling were not expected to result in more flow blockage.
Some temperatures of interest were:
3455'F - Eutectic forms (NUREG/CR-1250,"' Volume 2, Part 2, p. 513) 5148'F - UO2 melts During a design basis LOCA, the hottest cladding temperature will be at or slightly below 2200*F before the core is quenched by emergency core cooling water. Using the AT calculated for 44%
strain, the effect of fuel settling into ballooned regions will raise peak cladding temperatures by 46*F to about 2250*F, and peak centerline temperatures 900*F above this to about 3150*F.
These temperatures were well below those needed to cause loss of coolable geometry, or release copious quantities of non-volatile fission products or actinides from the fuel matrix via melting or eutectic formation. The only effect would be to drive off more noble gases and iodine.
O 12/31/98 3.92-2 NUREG-0933 l
Ravision 1
, in the WASH-1400" calculations for Release Categories PWR-9 and PWR-8 (mitigated LOCA with and without containment isolation), it was assumed that 3% of the noble gases and 1.7% of !
the iodine are released to the containment. These figures were scaled up such that all the noble l gases are released, i.e., it was assumed that the radiological consequences of a fuel pin segment '
exceeding 2200*F at the cladding are 331/3 times those of these two release categories. Thus, 100% of the noble gases and 57% of the iodine would be released from fuel which exceeds 2200*F at the cladding. This was a bounding calculation.
The next question was, given a uniform 46*F increase in cladding temperature throughout the core, what fraction of the core will exceed the 2200
- F licensing limit during the LOCA? Previously, only the hottest point touched 2200*F. Generally, a 10*F change in PCT corresponds roughly to I at most a 0.01 change in Fa for temperatures up to 2200* F. This rule of thumb was combined with three-dimensional power distribution information.es The result was that a uniform 46*F rise will result in roughly 0.015 o' W core exceeding the 2200*F limit. The consequences due to
]
core-wide uniform balloon e .id fuel setting were then bounded as follows:
AR (containment isolated) s (0.015)(331/3)(120 man-rem /PWR-9) s 60 man-rem AR (containment not isolated)s (0.015)(331/3)(75,000 man-rem /PWR-8) s 37,500 man-rem As discussed earlier, it was assumed that a portion of each fuel rod totaling 10% of its length i balloons well in excess of 44% strain. If this strain were 89% as in the second PBF calculation, and if the section in question previously just touched the 2200'F PCT limit, the revised peak l cladding and centerline temperatures would be roughly 2600*F and 4640*F, respectively. The !
centerline would not be hot enough to melt and the cladding would not be hot enough to form a
- eutectic, but, given the roughness of these estimates, the possibility of a copious release of fission products cannot be ruled out. Accordingly, no attempt was made to base a calculation on the degree of ballooning, but instead the radiological consequences were bounded by assuming that these 10% sections of each fuel rod release fission products as if they were molten. (it was assumed that there was no probability of containment overpressure or other mechanistic consequence normally associated with a enre-melt.) Because 0.1 of the mass of the core was affected, one-tenth of the radiological consequences of a PWR-7 release (core-melt with no containment failure) and a PWR-5 release (core-melt with failure of the containment to isolate) were used. The increase in consequences due to enhanced release at the rupture points on each fuel rod were then calculated as follows:
AR (containment isolated) s (0.1)(2300 man-rem /PWR-7) !
s 230 man-rem i AR (containment not isolated)s (0.1)(1,000,000 man-rem /PWR-5) s 100,000 man-rem Combining these values, the public risk associated with this issue was estimated to be as follows:
1 AFR s (4 x 10d LOCAs/RY)(0.10 near design basis LOCAs/LOCA) x ((0.9 '
containment isolation /DBLOCA)(60 + 230) man-rem + (0.1 isolation failure /DBLOCA)(37,500 + 100,000) man-rem] I 12/31/98 3.92-3 NUREG-0933
I Revision 1 s 0.56 man-rem /RY For a 30-year plant life, the public risk was estimated to be about 20 man-rem / reactor.
Cost Estimate Industry Cost: A possible fix was to reduce Fo limits by about 0.05 which would lower the calculated PCT by about 50* F. This would make it harder to maneuver the plant; startups and load changes would take longer. If a plant is or becomes LOCA-limited, this would also cause a derate.
In addition, changes in the ECCS analysis generally involve considerable administrative expense. l As a minimum cost, it was assumed that 5 startups (scram recoveries) a year would be extended t by one hour, and that one staff-year (including NRC staff time) and $50,000 of computer expanse would be expended in TS changes. Thus, the total cost over a 30-year period would be at least
$1M/ reactor.
NRC Cost: The NRC cost was negligible compared to the industry cost.
Value/ Impact Assessment Based on an estimated public risk reduction of 20 man-rem and a cost of $1M for a possible l solution, the value/ impact score was given by:
S = 20 man-rem / reactor
$1M/ reactor
= 20 man-rem /$M CONCLUSION The above calculations indicated that this issue should be placed no higher than the low priority category. This meant that there was insufficient risk-based justification for starting a major re-review of existing ECCS Appendix K performance analyses. However, it was noted that there were ongoing efforts to develop and license ECCS performance models that were more realistic
! (and consequently less conservative) than the models in use at the time of this evaluation in July 1984.
It was not valid to conclude that the effects of fuel crumbling and settling into ballooned regions could necessarily be neglected in any new, more realistic models. Instead, it was expected that these effects (which are real physical phenomena) would be appropriately addressed in the calculations. Moreover, a separate generic issue on fuel crumbling was not necessary; such work was best done within the scope of the review of the new calculational methodology. Thus, the l issue was given a low priority (see Appendix C). In NUREG/CR-5382,'5" it was concluded that consideration of a 20-yearlicense renewal period did notchange this priority. Further prioritization, using the conversion factor of $2,000/ man-rem approved'"' by the Commission in September 1995, resulted in an impact /value ratio (R) of $50,000/ man-rem which placed the issue in the DROP category.
O 12/31/98 3.92-4 NUREG-0933
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\ REFERENCES Q 16. WASH-1400 (NUREG-75/014), " Reactor Safety Study, An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," U.S. Nuclear Regulatory Commission, October 1975.
161. NUREG/CR-1250, "Three Mile Island: A Report to the Commission and to the Public," U.
S. Nuclear Regulatory Commission, January 1980.
622. Memorandum for T. Speis from R. Mattson, " Fuel Crumbling During LOCA," February 2, 1983.
633. Memorandum for P.' Check from H. Richings, "Some Notes On PWR (W) Power Distribution Probabilities for LOCA Probabilistic Analyses," July 5,1977.
634. NUREG-0630, " Cladding Swelling and Rupture Models for LOCA Analysis," U.S. Nuclear Regulatory Commission, April 1980, 1563. NUREG/CR-5382, " Screening of Generic Safety Issues for License Renewal I
. Considerations," U.S. Nuclear Regulatory Commission, December 1991, 1689. Memorandum to J. Taylor from J. Hoyle, "COMSECY-95-033 - Proposed Dollar per Person-Rem Conversion Factor; Response to SRM Concoming issuance of Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission and SRM Conceming the O Need for a Backfit Rule for Materials Licensees (RES-950225) (WITS-9100294),"
September 18,1995.
l 12/31/98 3.92-5 NUREG-0933
Rsvision 2 l
l I
ISSUE 107: MAIN TRANSFORMER FAILURES DESCRIPTION Historical Backaround This issue was identified in a DUNRR memorandum"" which called for en assessment of the high failure frequency of main transformers and the resultant safety implications. Concem for this issue arose when the North Anna Power Station had seven main transformer failures in 26 months; five of these resulted in reactor trips. Of the seven failures, three included rupture of a transformer tank that resulted in two fires. One of the fires spread beyond the transformer bay to
' the turbine bay. In a report"" prepared for the NRC by LLNL, it was concluded that there was a l possibility of generic implications arising out of the plant-specific failures reposted for the North Anna units. l The potential generic concems identified in the LLN L report"" included the fire protection system, overhead conductor / buses, cable trays, storage of flammable materials, and oil-filled transformers in general. In addition, certain secondary aspects of the transformer failures were identified which included cascading effects, extensive electrical / mechanical damage, and missiles / explosions, ,
although the LLNL report noted that these latter items appeared to be either indirectly or remotely related to specific safety-significant concems. Existing NRC regulations and guidance pertaining to fire protection and some of the generic concems raised in the LLNL report"" are embodied in i
10 CFR 50 Appendix R, the SRP," and Regulatory Guide 1.120."" In this analysis, the need for additional actions by the licensees to prevent main transformer failures and to reduce the resultant risk were evaluated.
Safety Sionificance Safety-related loads in nuclear power plants are supplied from buses that can be supplied from j any one of the following sources: (1) the unit auxiliary (main) transformer; (2) the startup ~
transformer (or reserve auxiliary transformer); or (3) the emergency onsite power supply (i.e.,
diesel generators). A main transformer failure will result in a loss of load or unbalanced load on the main generator. This would lead to turbine / generator trip and power would not be available to the unit transformers for the station power; however, station power can be obtained from the grid j through the startup transformer or from emergency onsite power sources. Switchyards have . -
redundant systems to provide sufficient relaying and circuit breakers so a transformer failure is not expected to cause a loss of offsite power, ,
i Other generic concems associated with this issue included: (1) oil from a ruptured transformer j could float on the water delivered to extinguish the fire by the fire protection system such that the :
fire will move in the direction of drainage; (2) the fire may propagate to overhead cables and buses l and create the need for access to adjacent locations (such as building roofs) by fire-fighting crews. j Possible Solutions Resolution of this issue could involve the following actions:
12/31/98 3.107-1 NUREG-0933
Revision 2 (1) Evaluation of main transformer design and arrangements by licensees to ensure that the supply of offsite power is protected against transformer fires and smoke. Design requirements should be established for routing and separation of offsite power source feeds to protect against power loss due to a transformer fire.
(2) Review of fire protection system features for the main transformers for adequacy and revision, as necessary, to ensure that a potential fire is prevented from spreading to other plant areas. The review should address the deluge system, drainage system, fire barriers, and fire-fighting equipment and procedures.
(3) Review of maintenance and operating procedures for the main transformers for adequacy and revision, as necessary.
(4) Modification of drainage systems, if necessary, to provide drains for each transformer so that liquids flow away from the turbine building, power lines, and safety-related cables to the reactor and related safety equipment. Modifications could include adding drains, building dikes, and sloping the transformer yard away from buildings and other transformers.
1 (5) Modification of fire-fighting equipment and procedures, if necessary. This could include longer hoses, increased ease of access to building roofs, mobility of fire-fighting equipment, and training for personnel.
(6) Relocation of powerlines to the safety-related buses, if necessary, so that they would not l be affected by a fire in the transformer bay. l PRIORITY DETERMINATION To establish the priority of this issue, the potential reduction in core-melt frequ,ency as a result of improved main transformer reliability due to implementation of the proposed solutions was quantified. It was believed that improved reliability of main transformers would reduce the frequency of transients induced due to main transformer failures, thus leading to enhanced plant safety.
Freauency Estimate in the representative plant PRAs (Oconee-3 for PWRs and Grand Gulf-1 for BWRs), main transformer failures are integrated into a category of transients that result from loss of network load. The affected PRA parameters are transients other than loss of offsite power requiring or resulting in a reactor shutdown, i.e. T2 (frequency of 3/RY) and Tu (frequency of 7/RY) for Oconee-3 and Grand Gulf-1, respectively. It was assumed that implementation of the possible solutions would enhance the reliability of main transformers and thus reduce the frequency of the resultant transients.
Data in NUREG/CR-3862"'8on a specific transient category, characterized as a loss of incoming power to a plant as a result of onsite failure (such as main transformer failure), suggest that the transient frequency associated with this category is 0.02 event /RY. In addition, the IEEE reliability data for liquid-filled transformers (347 to 550 KVA) at nuclear power plants indicate that the main 12/31/98 3.107-2 NUREG-0933
Rsvision 2 O transformer failure rate due to all causes was 2.67/million-hours. This corresponded to an annual
{
frequency of 0.023 failure / year for main power generator or unit transformers. This value was used as the base case for the failure frequency of main transformers. The second aspect of the main transformer failure, the risk from resulting fire, was determined to be insignificant and was not analyzed further. This conclusion was based on the findings of the Oconee-3 PRA which included the analysis of fires and their potential for causing failures of redundant safety-related compor.ents. Also, no particular sensitivity to main transformer fires was identified in NUREG/CR-5088.1211 It was assumed that implementation of the possible solutions (i.e., no design improvements to the transformer but improved maintenance and mitigative designs / procedures) would increase the reliability of main transformers by 50%. Therefore, the adjusted case main transformer failure frequency was estimated to be 0.01 event /RY. In addition, the adjusted case frequencies of the resultant transients (T2 and T 23) were estimated as follows:
T2 = (3 - 0.01)/RY
= 2.99/RY Ts 2 = (7 - 0.01)/RY
= 6.99/RY Incorporating these values in the Oconee-3 and Grand Gulf -1 PRAs provide reductio