ML20212J487
| ML20212J487 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 01/21/1987 |
| From: | Muller D Office of Nuclear Reactor Regulation |
| To: | Birely W PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC |
| References | |
| CON-FIN-A-3829, REF-GTECI-105, REF-GTECI-NI, TASK-105, TASK-OR NUDOCS 8701280212 | |
| Download: ML20212J487 (2) | |
Text
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January 21 0 1987 Dockets Nos.: 50-277/278 DISTRIBUTION iDetteta F11e -~
NRC PDR/L'PDR Mr. William Birely RMBernero/0GC-Bethesda Senior Licensing Engineer EJordan/BGrimes Philadelphia Electric Company JPartlow/NThompson 23G1 Market Street RClark/DRMuller Philadelphia, Pennsylvania 19101 SNorris/ACRS (10)
PD#2 Plant File
Dear Mr. Birely:
RWood (DSR0)/WMinners (DSR0)
SUBJECT:
BROOKHAVEN NATIONAL LABORATORY PRA CONCERNING INTERFACING SYSTEMS LOCA AT LWRS (GENERIC ISSUE #105)
As part of the research effort on Interfacing Systems LOCAs to Resolve Generic Issue 105, we had requested by letter dated April 7,1986 your assistance in obtdining information to support a study of this Generic Issue. By letter dated May 2,1986, PEC0 responded affirmatively to our request and you were designated as the Philadelphia Electric point of contact in this effort. We wish to thank you for your_ support in this effort. Your personnel provided useful information both in written form and through a plant trip that Brookhaven personnel made to the Peach Bottom site.
The information which you provided was considered by the Brookhaven personnel in producing the enclosed draft report dated May 1986. We are transmitting the report both for your information and for any comments you deem appropriate.
We would particularly be interested in any input you could provide regarding the costs (even " ball-park" estimates) of the possible alternatives that are outlined in the enclosed draft. The next Brookhaven task is a cost / benefit analysis to assist the NRC staff in reaching a decision on what action to take on this issue.
If you have any questions, please feel free to contact the authors of the draft report (516-282-7204 or 516-282-2389), Mr. Roy Wood, the NRC Task Manager for Generic Issue 105,(301-492-4712) or Dick Clark, the Peach Bottom Project Manager (301-492-8298). Please convey our thanks and appreciation to your staff for their continued cooperation and assistance in evaluating this safety issue.
Sincerely, gul t.igaed by Danist it Mu!!ct j
~
B701280212 B70121 Daniel R. Muller, Director PDR ADOCK 05000277 PDR BWR Project Directorate #2 P Division of BWR Licensing
Enclosure:
As stated cc w/o enclosure:
See next page DBL: D#2 DBL:PD#2 DBL:Pyy SNo r s RClark/ DRM41er l /,21/87 o/ /2/ /87 / /t 1/87 0FFIM AL_$ECORD COPY _ . . _ . . _ _ . _ __ _ _
. .- - ~ ~ . . . . . . . . - ,
Mr. William Birely Peach Bottom Atomic Power Station, Philadelphia Electric Company Units 2 and 3
.N.
cc: :.
Mr.Eugenei{.Bradley Mr. R. A. Heiss, Coordinator Assistant General Counsel Pennsyl ania State Clearinghouse Philadelphia Electric Company Governor's Office of State Planning 2301 Market Street and Development Philadelphia, Pennsylvania 19101- Post Office Box 1323 Harrisburg, Pennsylvania 17120 Troy B. Conner, Jr., Esquire 1747 Pennsylvania Avenue, N.W. Mr. Thomas M. Gerusky, Director Washir:gton, D.C. 2000f Bureau of Radiation Protection Pennsylvania Department of Thomas A. Deming, Esquire Environmental Resources Assistant Attorney General Post Office Box 2063 Department of Natural Resources Harrisburg, Pennsylvania 17120 Annapolis, Maryland 21401 Mr. Albert R. Steel, Chairman Mr. R. Fleishmann, II, Manager Board of Supervisors Peach Bottom Atomic Power Station Peach Bottom Township R. D. #1 R. D. #1 Delta, Pennsylvania 17314 Delta, Pennsylvania 17314 Mr. G. M. Leitch, Superintendent Mr. Edward G. Bauer, Jr.
Nuclear Generation Division Vice Pres, & Gen. Counsel b7-1 Philadelphia Electric Co.
Philadelphia Electric Company 2301 Market Street 230: Market Street Philadelphia, Pennsylvania 19101 Philadelphia, Pennsylvania 19101 Mr. Anthony J. Pietrofitta, General Manager Power Production Engineering Atlantic Electric Pop Office Box 1500 1199 Black Horse Pike Pleasantville, New Jersey 08232 Resident Inspector U.S. Nuclear Regulatory Commission Peach Bottom Atomic Power Station Post Office Box 399 Delta, Pennsylvania 17314 Regional Administrator, Region I U.S. Nuclear Regulatory Commission 631 Park Avenue King of Prussia, Pennsylvania 19406 6
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FIN A-3829 INTERFACING SYSTEMS LOCA AT BWRs DRAFT LETTER REPORT T. Chu, S. Stoyanov, R. Fitzpatrick Risk Evaluation Group May 1986 Department of Nuclear Energy Brookhaven National Lah'ratory Upton, NY 11973
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1-1
- 1. INTRODUCTION :
1.1 Backgr und l
The Reactor Safety Study, WASH-1400,1 identified an intersystem loss-of-coolant accident in a PWR as a significant contributor to risk from core melt accidents (Event V). As a result of the study and'the TMI-2 accident, all light water reactors with operating license on February 23, 1980 were reqtired 2-3 to periodically test or continuously monitor the Event V valves.
The Event V arrangement is defined to be (1) two check valves in series, or (2) two check valves in series with an open motor-operated valve. Such valve arrangements are commonly used in PWRs but not BWRs. Acceptable methods to-assure component integrity include:
(1) continuous monitoring on the low pressure side of each check valve, p (2) periodic IST leakage testing on each check valve every time the plant is shutdown and/or each time either check valve is moved from the '
fully closed position,
- (3) periodic ultrasonic examination on each valve every time the plant is shutdown and/or each time either check valve is moved from the fully closed position, or
- (4) periodic radiographic examination on each valve every time the plant is shutdown and/or each time either check valve is moved from the fully closed position.
I For plants which received operating licenses after October 1980, leak tests
, of all pressure isolation valves (that is; two valves in series which separate I high pressure RCS from associated low pressure systems) are required." Systems that are rated at full reactor pressure on the discharge side of pumps but have pump suction below reactor coolant system pressure are not normally considered to be barriers unless the pumps are of the positive displacement type. Pressure "No plant has ever proposed these methods and thus such methods have not received a detailed review.
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1-2 isolation valves are required to be Category A or AC per IWV-2000 of ASME Code for Boilers and Pressure Vessels. Limiting conditions of operation and surveillan.ch. requirements are specified in Technical Specifications. The leak testprografsoftheapplicantswerereviewedbytheMechanicalEngineering Branch, Division of Engineering, NRR, until the recent NRR reorganization.
Vendor program branches now conduct these reviews. A proposed Appendix A to Standard Review Plan, Section 3.9.6 was written to include leak' testing of pressure isolation valves but was never approved.5 Since early 1981, the NRR staff has been backfitting operating reactors by requiring, via inwservice inspection programs, leak testing of all PIVs that connect the high pressure RCS to lower pressure systems. 6 This backfit has been completed on approximately 15 plants licensed prior to the accident at'Three Mile Island. On April 20, 1981, orders were sent to 32 PWRs and 2 BWRs which required leak rate testing of event V PIVs.
Due to the questionable basis for the 1 gpm acceptance criterion for leak rate tests from Near Term Operating License (NTOL) applicants,7 the NRR staff changed the acceptance criterion.8 The leak rate on each valve must be no greater than 1/2 gallon per minute for each nominal inch of valve size and no greater than 5 gpm for any particular valve. On July 24,1985, .the Committee to Review Generic Requirement (CRGR) responded favorably to this change,9 but questioned the safety rationale that is used to justify the full extent of the PIV testing that is required of NTOLs, and the retroactive applications to the operating reactors. To address the concern of CRGR, NRR put a program in place under Generic Issue 105 to develop the necessary information to prepare a new NRC staff position on testing of PIVs. The current leak testing requirements for PIVs are stated in the PWR standard technical specifications as follows:
- a. At least once per 18 months.
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- b. Prior to entering hot shutdown when the plant has been in cold shutdown
- for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or more and if leakage testing has not been performe'd in
, the prev.ious 9 months.
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_ _ . _ _ -_. - _ _ _ _ ____. _ ._ , _ _ . . ~ _ _ , _ . -
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- c. Prior to returning the valve to service following maintenance, repair or replacement work on the valve.
.l. - '
- d. Wi hin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following valve actuation due to automatic or manual .
action or flow through the valve.
In BWRs, items b and d have. been omitted in many recent licensing actions ;
because the PIVs have readout in the control room and alarms if pressure is exceeded on the low pressure side. In some cases interlocks are provided to
, prevent both valves from being opened when the pressure is too high. NRR recently recommended the elimination of requirements b and d in all plants as being too stringent.10 Item d above is believed to impose the most hardship on utilities in terms of its potential effect on plant operation because leakage in excess of the acceptance criterion requires that the plant be brought back to cold shutdown to repair the failed valve.
1.2 Objective Recent operating experience indicates that the pressure isolation valves may not adequately protect against overpressurization of low pressure systems i
unless their integrity is verified by periodic testing as outlined above.11 Overpressurization of low pressure system may result in rupture of low pressure piping.- This, if combined with failures in the emergency core cooling systems, would result in a core melt accident with an energetic release outside the containment. Some ECCS failures may be a direct result of the rupture and/or its environmental affects.
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The objective of this work is to provide technical support to the NRC, Reactor Safety Issues Branch, for the meaningful resolution of the generic issue. This work includes, survey and analy. sis of representative plants to l determine core melt risk due to failure of pressure isolation valves, and determination of corrective actions such as valve leakage testing or not testing at pressure.
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1.3 Organization of Report Chapte 2 and Appendix A provide detailed information on the interfacing linesidentyledfortheselectedplants. Chapter 3 and Appendix B provide detailed information on the survey of operating experience, and the causes of P1V failures. Chapter 4 and Appendix C provide the detailed quantification for the interfacing lines identified.in Chapter 2 using the failure experience and data found in Chapter 3 and Appendix D, respectively. Chapter 5 provides recommended changes that could be made to address the significant items identified from the Chapter 4 results in order to lower the core damage frequency from interfacing systems LOCA.
1.4 References
- 1. " Reactor Safety Study - An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plant," WASH-1400 (NUREG-75/014), USNRC, October 1975.
- 2. Letter to all LWR licensee on " LWR Primary Coolant System Pressure Isolation Valves," from Darrel G. Eisenhut, Acting Director, Division of Operating Reactors, Office of Nucleac Reactor Regulation, USNRC, February 23, 1980.
- 3. " Order for Modification of License Concerning Primary Coolant System Pressure Isolation Valves," Letter from Darrel G. Eisenhut, Director, Division of Licensing, Office of NRR, USNRC, to Eugene R. Mathews, Vice President, Power Supply and Engineering, Wisconsin Public Service Corporation, April 20, 1981.
- 4. Leak Tight Integrity of Primary Coolant System Pressure Isolation Valves,"
l Memorandum from J. Knight, Assistant Director for Components and Structure Engineering, Division of Engineering, to R. Tedesco, Assistant Director for Licensing, Division of Licensing, Office of Nuclear Reactor Regulation, USNRC, October 15, 1980.
- 5. " LWR Reactor Coolant System Pressure Isolation Valves," Memoraudum from l Darrel G. Eisenhut, Director, Division of Licensing, to Richard H. Vollmer, Director, Division of Engineering, Office of NRR, USNRC, March 30, 1981.
1-5
- 6. " Leak Test Requirements for Reactor Coolant System Pressure Isolation Valves," Memorandum from G. E. Edison, Chief, Technical and Operations SupportIBranch Planning and Program Analysis Staff, to Harold R. Denton, Office NRR, USNRC, June 14, 1985.
- 7. " Pressure Isolation Valve Leak Test Acceptance Criteria - NTOLs," Memorandum from James P. Knight, Assistant Director for' Components Structures Engineering, Division of Engineering, to Richard H. Vollmer, Director, Division of Licensing, Office of NRR, USNRC, May 11, 1983.
- 8. " Proposed Technical Specification Change and Notice Regarding Acceptable Pressure Isolation Valve In-Service Test Leak Rates," Memorandum from Harold R. Denton, Director, Office of NRR, to Victor Stello, Jr., Committee to Review Generic Requirements, USNRC, February 14, 1985.
- 9. " Minutes of CRGR Meeting Number 79," Memorandum for William J. Dircks, Executive Director for Operations, from Victor Stello, Jr., Chairman, Committee to Review Generic Requirements, August 21, 1985.
- 10. " Leak Rate Testing - Pressure Isolation Valves," Memorandum from Harold R.
- Denton, Director, Office of NRR, to James Sniezek, Acting Chairman, Committee for Review of Generic Requirements, USNRC, March 3, 1986.
- 11. P. Lam, "Overpressurization of Emergency Core Cooling Systems in Boiling Water Reactors," Nuclear Regulatory Commission Office for the Analysis and Evaluation of Operating Data, February 1985.
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- 2. SURVEY OF REPRESENTATIVE BWR PLANTS Three. WRs were selected for detailed analysis regarding interfacing system LOCA. They are Peach Bottom, Nine Mile Point-2, and Quad Cities. Table 2.1 lists some important characteristics of these plants. Information on the interfacing lines in the selected plants was collected. Appendix A provides information on the lines identified, including valve arrangement, automatic and-manual control, and potential indications of overpressurization or LOCA.
Section 2.1 describes the method used to identify interfacing lines, and some general observations. Section 2.2 discusses the detailed information that was sought for assessing frequencies of overpressurization, and conditional probability of core damage given an interfacing LOCA.
2.1 Identification of Interfacing Lines in Selected BWRs Some information on interfacing lines in light water reactors 1.s provided in a study by Oak Ridge National Laboratory. I However, because that study was performed in 1981, some of the information may not be up to date. This was pointed out by a recent Event V inspection conducted on all Region I reactors
- . including Peach Bottom.2 Reference 2 provides some information'on interfacing lines at Peach Bottom but not Nine Mile Point-2 or Quad Cities.
6 Interfacing lines for the selected plants have been identified using l their FSARs. Each FSAR has a table of containment isolation valves for all lines penetrating containment. These tables have been incorportated into
, Appendix A. Some of the lines penetrating containment are not connected to the reactor coolant system, e.g. , the RHR containment spray line. Such lines were not analyzed further. The remaining lines are connected to the reactor coolant i system and, therefore, at least portions of these lines are rated for high
! pressure. The piping and instrumentation diagrams (P&ID) and the process diagrams for the corresponding systems were reviewed to determine the high/ low pressure interfaces. The following criteria were used to eliminate some lines as being not important or outside the scope of this interfacing system stuIdy.
, ,- , e - - - , - - , - -
.---s
2-2 A. High Energy Lines - Lines that are designed for high pressure are not considered further. For example, main steam lines, steam supply lines for RCICahdHPCIturbines,andlinesinthereactorwatercleanupsystem.
B. Small Lines - Lines with diameters less than 1-1/2" are not considered. For example, sample lines, control rod drive insert or withdraw ' lines, and standby. liquid control injection lines. Breaks in these lines have not been included because they do not directly impact on the needed safety systems and the resulting leakage is expected to be small.
C. Injection Line of Control Rod Drive Pumps - The system consists of two pumps in parallel, one normally operating, the other normally on standby.
The standby pump is isolated from the operating pump by a check valve and a manual valve on the discharge side and a manual valve on the suction side.
The discharge side of the system is high pressure and the suction side of the pumps is low pressure. One scenario of an interfacing LOCA is that the discharge valves of the standby pump fail open, back-flow through the pump overpressurizes the pump suction and causes the suction manual valve to rupture. This disturbs the suction side of the operating pump and causes it to trip. At this time, a small LOCA is resulted through the standby pump train. The operator can also isolate this by closing the MOVs in the discharge line. The frequency of such a LOCA is expected to be quite low and even if such a LOCA should occur, the flow would be limited by the size of the smallest pipe section which is typically 1-1/2". Therefore, based upon the ability to isolate, the lack of direct impact on mitigating systems and the limited flow potential, these lines have not been included -
in the succeeding phases of this study.
. D. Lines that are Connected to the Primary Coolant Pressure Boundary l Outside the Containment by Normally Closed Pressure Isolation Valves (PIVs)
- If the failure of the PlVs in a given line does not result itself in a LOCA, then an additional failure of the containment isolation valves will i be needed for an interfacing LOCA to occur. The frequency of such a scenario will be quite low. For example, the feedwater flush line at Peach Bottom is 12" in diameter, and is isolated from the feedwater pressure by i
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7 __7___; .__
2-3 two normally closed valves (PIVs). If the normally closed valves fail open
, and feedwater pressure causes the flush line to rupture. Feedwater will be diverthd'throughthebreak. LOCA will not occur unless the feedwater check i
valve side the containment failslto close when the main feedwater pump is tripped. If this check valve does fail to close, the control room operator
- can isolate the MOV downstream of this check valve. Similarly, in the reactor water c1 nup system, there are many low presure lines used for backwash and preevat of the filter demineralizer. They are isolated from high pressure piping by two normally closed valves. If the valves fail open and cause a rupture of low pressure piping, the containment isolation valves should isolate.the reactor water cleanup system from the primary coolant system. LOCA in these lines then requires failure of two j containment isolation valves that are not the PIVs, as well as failure of the two PIVs. Therefore, the frequency of LOCA is again expected to be quite low compared to those lines listed in Table 2.2 which represent the interfacing lines selected by this phase of the study for further analysis.
1
< E. Lines that are not Connected to the Reactor Co'olant System Need not be Considered - Some of the lines penetrating containment do not make any f
connection to the primary system, for example, the drywell purge lines.
{ Such lines could not cause a LOCA upon their failure and thus do not fall
[ within the scope of this study.
All lines penetrating containment and not climinated using the above criteria were analyzed further. P& ids that show all lines connected to the primary system were also reviewed to be sure no line would be overlooked. The information collected for the identified lines is given in Appendix A. Figures 2.1 and 2.2 are simplified drawings showing major components in the systems that have lines penetrating the containment. Appendix A provides a table which lists lines penetrating containment for each of the three plants in this study. The single character code in the first column of each table denotes the disposition l
of line. An asterisk indicates that the line is considered within the study.
A letter means that the line is not further considered, based upon the screening criterion denoted above by the same letter.
l 1
2-4 Based on the survey of the three selected BWRs, the following were observed:
- Thehilowingsystemsarehighpressureonthedischargeside '
of the pumps, but low pressure on the pump suction sides: Reactor core isolation cooling system (RCIC), high pressure coolant injection system (HPCI), high pressure core spray system (HPCS), control rod drive system, standby liquid control system, and feedwater system.
- The feedwater line is somewhat unique in that the feedwater system is normally operating. The feedwater discharge line is high pressure but the pump suction side is low pressure. The water hammer event at San 3
Onofre-1 was caused by common cause failure of multiple check valves.
Chapter ~s and Appendix B provide more detail of the incident. If the analogous event had occurred in a BWR, a large interfacing LOCA could have resulted.
. The reactor water cleanup (RWCU) system has a blowdown line downstream of the filter demineralizer. It is connected to the condenser through low pressure piping. The line can be used when reactor is at power. A restricting orifice reduces the pressure before the flow reaches the low pressure piping. Overpressurization or pipe rupture may occur if a valve in the low pressure piping is closed. However, an isolation valve in the line itself is expected to close as a result and further, given its failure, the containment isolation valves will then act to isolate the system. This line is not considered further, because the frequency of unisolated interfacing LOCA in it is judged to be quite low compared to the lines listed in Table 2.2. In addition, as documented in Section 3.1, two separate data searches were undertaken to ascertain if any related failure experience exists for the RWCU systems. Based on these data searches, nothing was found to indicate this system should be included in the ensuing phases of this study.
2-5 2.2 Information Collected for Identified Lines Forenkhoftheinterfacinglinesidentified,thefollowinginformation was collect d and documented in Appendix A. I
- 1. Pressure Isolation Valves (PIVs) - These were obtained from the P& ids.
of the systems. The list, if available, of PIVs in Technical Specifications is used to check for completeness.
- 2. Surveillance Requirements for the PIVs and the System Pumps - Most of the PIVs are also-containment isolation valves for ECC systems. The tests they 4
may be subjected to are local leak rate test (LLRT) for containment isolation valves, leak rate test for PIVs, and valve operability test for valves in the ECCS.
- 3. Automatic and Manual Control of PIVs and the System They are In - This is based on P& ids and system descriptions in FSAR.
- 4. Valves that Will Bound the Low Pressure Piping that Will be Overpressurized, if the PIVs Fail Open - This is based on P& ids.
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- 5. Potential Alarms or Indications of Overpressurization or Interfacing LOCA - This is obtained by reviewing system descriptions, P& ids, process diagrams, functional control diagrams, and system descriptions for leakage detection system, radiation monitoring system, and HVAC for the reactor I building.
In addition to the information in Appendix A, attempts were made to collect i
information needed to assess what effects a postulated interfacing LOCA in the identified lines may have on safety systems that are needed to mitigate the accident. Intersystem effects may be caused by such things as flooding, overpressurization of compartments, high temperature steam damage, drainage of the condensate storage tank or the suppression pool. Typically, different ECC
- systems are located in different compartments as are pumps in different trains
- of the same system. The compartments are typically connected by water tight doors. Other potential interconnections include blow-out panels and HVAC i +
2-6 1 l ducts. The compartments are typically designed for an internal to external
-differential pressure of 0.25 psid. For those compartments that contain high energyline(, blow-outpanelsaretypicallyinstalledtorelieveanyblowdownto additional olumes. "High energy lines" are defined to be lines with operatin5 -
pressure greater than 275 psig or operating temperature greater than 200*F, e.g., RCIC steam line, main steam lines, and feedwater lines. Typically, the floor of the pump rooms is at the same level as th'e suppression pool. The suppression pool water level is approximately 20' or more. The suppression pool suctions of ECCS are more than 8' below the normal suppression pool level and the suction piping usually slopes down to the pump, such that the suction piping is always filled with water to provide the needed net positive suction head. If the suction piping is ruptured, loss of suppression pool inventory may be a problem.
To the extent attainable in one-to-two day plant site visits, the above classes of information were persued by plant tour and/or interviews with key I plant personnel. The results of these visits played an important role in 1
- formulating many of the assumptions found in the following sections of this j report. Every attempt has been made to indicate the origin and basis for each j such assumption whenever it is introduced.
2.3 References
- 1. Fred A. Heddleson, " Summary' Report on a Survey of Light Water Reactor Safety Systems," Oak Ridge National Laboratory, NUREG/CR-2069, October 1981.
- 2. "Special Inspections Regarding Potential Intersystem Overpressurization of Emergency Core Cooling Systems (Event V Inspections)," Memorandum from Thomas E. Murley, Regional Administrator, Region I, to James M. Taylor, Director, Office of Inspection and Enforcement, USNRC, September 18, 1985.
- 3. " Loss of Power and Water Hammer Event at San Onofre Unit 1, on November 21, 1985," USNRC, January 1986.
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bl.- j GROUP CLASSIFICATION DIAGRAM N!AGARA MOHAWK POWER CORPORATION NINE MILE POINT-UNIT 2 FillAL SAFETY ANALYSIS REPORT Figure 2.2 A simplified drawing for lines penetrating containment at Nine Mile Point-2.
2-9 Table 2.1 Characteristics of Selected BWRs Peach Bottom . Nine Mile Point-2 Quad Cities Containment Type Mark I Mark II Mark I BWR 4 5 3 AE Bechtel Stone & Webster Sargent & Lundy Design Power (MWe) 1065 1080 789 RHR Heat Exchangers 4 2 2 Pumps 4 3 4 Pumps for Shutdown Cooling Mode 4 2 4 Injection Location Recirculation Vessel Recirculation Line Line LPCI Containment 2 3 2 Penetration Steam Condensing Line to RRR Heat Exchanger No Yes No LPCI Discharge Cross Connection Yes No Yes Service Water Connection Yes Yes No Fuel Pool Cooling Connection Yes Yes Yes LPCS Pumps 4 1 2 Injection Line 2 1 2 HPCI Yes No Yes HPCS No Yes No CST 1 per unit 2 2 RCIC Injection Location Feedwater Vessel Head Feedwater Line Line
2-10 Table 2.2 Interfacing Lines Identified for Analysis Pdhch Bottom .
i LPCI Injection Lines Shutdown Cooling Suetica Line RPV Head Spray Core Spray Injection Lines HPCI Pump Suction' RCIC Pump Suction Nine Mile Point 2 LPCI Injection Lines Shutdown Cooling Suction Line RPV Head Spray Low Pressure Core Spray Injection Lines HPCS Pump Suction RCIC Pump Suction Shutdown Cooling Return to Recirculation Steam Condensing Supply Line to RHR Heat Exchanger Quad Cities LPCI Injection Lines Shutdown Cooling Suction Line RPV Head Spray Core Spray Injection Lines HPCI Pump Suction RCIC Pump Suction f
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i 5
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i 3-1 I
1
- 3. SURVEY OF OPERATING EXPERIENCE AND IDENTIFICATION OF CAUSES OF FAILURE 3.1 Survey of Operational Events Involving Failures of Pressure Isolation Valvesf After the Browns Ferry-1 event on August 14, 1984,1-2-3 AEOD looked at operating experience dating back to 1975 to identify events involving actual and potential overpressurizations of emergency core cooling systems.1 The scope of the search included all emergency core cooling systems as well as the reactor core isolation cooling system in BWRs. Eight incidents were identified. A summary of the events is provided in Table 3.1.
To expand the search for operational events involving pressure isolation valve (PIV) failures, BNL performed the following searches using the RECON" data base.
. A search for valve failures in ECCS systems and RWCU system was done on February 14, 1986 for events reported in the 1981 to 1986 period.
. A search for valve failures in ECCS systems and RWCU system was done for events reported before 1975.
. A search for check valve failures in feedwater systems of both PWRs and BWRs was done on April 20, 1986.
The search for failures of feedwater check valves was'. performed to identify any failures similar to the San Onofre-1 event,5 in which 5 check valves in the feedwater lines failed open, resulting in a water hammer, and severe damage to the feedwater piping and supports.
i The RECON data base provides a one line description and an abstract for each identified event. First, the one line descriptions were reviewed. Those events involving valves that are not pressure isolation valves were skipped.
The abstracts of the remaining events were then reviewed. A few incidents involving failures of pressure isolation valves to pass local leak rate tests were found. They all involved very small leakage and were not considered further, except the event at Susquehanna-2.6 This event involved multiple failures of pressure isolation valves in the RHR system such that pressure at
3-2 the RHR heat exchanger was increasing. The plant was forced to shutdown in order to repair the failed valves. Table 3.2 provides a summary of the eleven incidents.thehavebeenidentifiedandincorporatedintothisstudy. They are orderedinhhronologicalorder. -
Appendix B provides detailed descriptions and associated valve arrangements of these events. Eight of the eleven incidents were identified by AEOD.1 Their descriptions were taken from Ref. 1. The description for the Susquehanna-2 incident was taken from the LER.6 The description of the Pilgrim incident in April 1986 was taken from Ref. 7. (It is interesting to note that Pilgrim replaced its air operated check valves by regular check valves after the event 8
on September 29, 1983 and, therefore, this recent incident involves failure of a regular check valve.) The San Onofre-1 incident 5 is included in the list, because if an analogous incident had happened in a BWR, a large LOCA outside the containment could have resulted.
3.2 Identification of Causes of Failures and Methods of Discoverv In this section, the valve failures in the incidents identified are described. The causes of failures are discussed if identified. Also provided are the ways the failures were discovered. This information was collected from references listed in Table 3.2.
3.2.1 Events Involving Failure of Testable Check Valves The first nine incidents of Table 3.2 involve failures of testable check valves. In these incidents, testable check valves are used inside the drywell in the injection lines of ECCSs of BWRs. Along with a normally closed MOV outside the drywell, the testable check valve serves as both containment isolation valve and pressure isolation valve. Technical Specification testing requirements for these valves are given in the tables of Appendix A. Figure 3.1 shows the structure of a testable check valve.15-16 It has an air operator controlled by a solenoid pilot valve. It also has a bypass valve that is needed to cycle the testable check valve when the reactor is pressurized.
. . _ _ _ _ . -_ _ _ _ . _ _ _ . _ . __ ._ _ ~ _
3-3 In this section, some descriptions of the operation of the testable check valves are provided. The causes of failures are discussed in Subsections I 3.2.1.1thrdbgh3.2.1.9.
The following description of testable check valves made by Rockwell International has been taken from Ref.15, and applies to the testable check valves at Hatch 2. Testable check valves at other plants may be made by I manufacturers other than Rockwell International, therefore, their detailed l design may be different.
Prior to a test opening via the air actuator, the bypass valve on the 1" line around the check valve is opened to equalize the pressure on both sides of the disk of the check valve. When the remote test push button is depressed, power is supplied to the solenoid pilot valve causing the pilot valve to shift. This in turn causes the actuator rod to rotate from its neutral position. When the actuator rod reaches its 150' position, it engages the check valve disk via a disk pin. Further rotation of the i actuator rod lifts the disk from the valve seat. The actuator rod will rotate another 30' to its 180' position where it will stop. The limit f
switch on the actuator gives an indication of actuator travel (the full
- 180' from neutral) via a light on the control panel in the control room. A
! proximity switch tripped by a ferrous can connected to the valve disk gives an indication of disk position (open) via another light on a control panel i in the control room. The isolation check valve which provides the first of b
3 t
two isolation boundaries between the RCS and the RHR system is a safety-related component, while its air actuator and the pilot solenoid i valve are not classified as safety-related.
i The following description of testable check valves made by Anchor Darling
! has been taken from Ref.12, and applies to the valves at LaSalle-l.
t i
The Testable Check Valve is exercised open by first opening the Testable Check Bypass Valve. This is done to equalize pressure across the check valve disc. -The Testable Check Valve is then cycled open by operating a j remote handswitch. This handswitch energizes a solenoid valve, opening it and causing the following to happen.
3-4
~
Instrument air is supplied to one side of an air piston cylinder which moves a rack and gear assembly against spring tension. This movement of theradkandgearassemblyrotatesalobedshaftconnectedthroughthegear approx pately 25' contacting the valve disc and lifting it off its seat. :
When the handswitch is returned to close, the solenoid valve de-energizes' closed securing instrument air to the air piston. Spr*ing tension returns the rack and gear assembly to its normal position. This rotates the lobed shaft connected through the gear away from the disc allowing the disc to closeduetoit'sownweightanddifferentialpre[sure.
3.2.1.1 Vermont Yankee Event on December 12, 1975 In this incident, testable check valve 10-46A was leaking past-its seat, while the indicator lights in the control room showed that the valve was fully closed. The failure was discovered because of the subsequent overpressurization of the low pressure piping. The cause of failure has not been reported.
MOV 10-25A initially failed to open during the valve operability test. It was manually opened. Then the valve was successfully cycled. The cause was reported to be excessive differential pressure across the valve seat resulting from the leakage through the testable check valve. This is judged not to be the only cause, because if check valve leakage always lead to failure of the upstream MOV, then experience would so indicate.
l MOV 10-27A is normally open. During the incident, it was closed according to procedure before MOV 10-25A was opened. However, it failed to close fully, leaving an 1" opening. The indication in the control room for this valve l falsely indicated that it was closed. The causes of the valve failure and the false indications were not reported. The failures were discovered because of the overpressurization. As the result of overpressurization, the RHR heat exchanger developed a leaking gasket on the fixed tube sheet to shell flange. A l
steam water mixture was discharged from the flange area and three RHR system i
relief valves.
l l
4 l
3-5 3.2.1.2 Cooper Event on January 21, 1977 Inthihincident, HPCI the testable check valve, A0-18, failed to remain fully close , due to a broken sample probe wedged under the edge of the valve I disc. The sample probe came from the main feedwater line upstream from where the HPCI discharges into the feedwater line. In order for the broken sample probe to get to the as-found position, the check valve disc must have been lifted from the valve seat. One possibility is that the check valve first leaked, and the piping between the check valve and the MOV, MO-19, was pressurized. With the pressure across the check valve dise equalized, the valve disc rattled due to vibration in the feedwater line. This failure was not recognized until the backflow of feedwater to the HPCI pump suction occurred.
It was not known if the position indication in the control room was indicating correctly.
With the testable check valve partially open, the outboard isolation valve j MD-19 was opened as required by the HPCI System Turbine Trip and Initiation
, Logic Surveillance Test. This resulted in backflow of feedwater to the pump suction piping. The isolation valve was then closed. It was not reported whether or not overpressurization of low pressure piping took , place.
If the low pressure piping was overpressurized to the point that it ruptured, diversion of feedwater and unavailability of HPCI would have resulted. An interfacing LOCA will not result unless the feedwater check valve t
. inside the drywell also fails in an open position upon feedwater trip.
3.2.1.3 LaSalle-1 Event on October 5,1982 c
( In this incident, a testable check valve was tested by cycling while the plant was operating at 20% power. This was done by first opening the bypass valve to equalize the pressure on both sides of the valve disc, and then operating a remote hand switch. A more detailed description of this operation has already been discussed in Section 3.2. After the test, both the testable f check valve and its bypass valve failed to indicate closed. The testable check
, valve was found to be 5% open.
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Normally, the preload on the actuator spring will return the actuator cylinder to its normal position after air pressure is removed. The checkvalvekiscwillthenclosebyitsownweightandpressuredifferentisl.
Thefailurehfthetestablecheckvalvetoreseatwascausedbysomecombination of the following. The lubricant on the actuator cylinder was dry, making it difficult for the cylinder to move. The preload on the spring was not sufficient to return the cylinder to its normal position.- And, the bypass valve stayed open, keeping the pressure equalized across the. check valve disc. The cause of the bypass valve failure was not reported.
3.2.1.4 LaSalle Event on June 17, 1983 Similar to the LaSalle-1 event on October 5, 1982, a testable check valve and its bypass valve failed to indicate closed after being opened by test. The cause of the check valve failure was found to be a stuck open bypass valve and possibly thermal binding of the check valve disc. The cause of the bypass valve failure was not reported. During shutdown of the plant, the bypass valve closed unassisted as reactor temperature and pressure decreased. This then allowed the testable check valve to close. The valve was examined and anadjustment to spring tension was made. A concern was raised that the check valve and its bypass valve tend to remain partially open after being cycled hot. A revision to the in-service-test of. pumps and valves was proposed to test the valve in cold shutdown only.
. 3.2.1.5 LaSalle-1 Event on September 14, 1983 i
i In this event, the testable check valve in the LPCI line failed open, i
{ resulting in draining of reactor coolant while performing RHR System Relay Logic
[ Test at cold shutdown. The operator was immediately aware of a reactor water level decrease and secured the flow path by closing the injection valve that was opened during the test. The valve failure was due to two causes, misalignment i of the interfacing gears between the check valve and the air operator, and tightness of the packing gland on the check valve shaft inhibiting free movement of the valve disk. Both causes were due to maintenance errors. The interfacing gear has a timing mark used to align the gears for proper reassembly after maintenance. The timing mark on the spline shaft of the check valve was i
3-7 1
confused with a score mark on the spline shaft. This aligned the check valve and tha air operator such that the check valve was 35' open when the air operator was in the fully closed position. The packing gland was adjusted too tight in theipreceding maintenance of the valve. The local leak rate test that
- was required af ter maintenance was inadvertently not performed. Otherwise, this problem would have been discovered and corrected.
3.2.1.6 Pilgrim-1 Event on September 29, 1983 In this incident, the HPCI testable check valve was partially open, and both RPCI pump discharge valves were inadvertently opened by the operator. The HPCI pump suction was overpressurized by the feedwater system precsure. The overpressurization caosed the gland seal condenser gasket to rupture. This in turn caused a mixture of water and steam to spray from the condenser to a nearby limit switch resulting in a 250-V de battery ground, and a large amount of water in the pump room. The operator relieved the pressure by opening valves in the HPCI test return line at one minute into the incident.
-The exact cause of the check valve failure was not determined. There was some evidence that a rusted linkage between the valve stem and the attached air operator had contributed to the failure. The rusted linkage was repaired and the check valve was returned to its correct position. In the short term, the testable check valve was tested by monitoring the pressure in the pipe section between the check valve and the outboard discharge valve. After 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> no pressure buildup was detected. In the long term, the testable check valve will l be replaced by a new design. Both discharge valves were opened at the same time. This was due to verbal miscommunication between the control room operator and an I&C technician.
The error consisted of conducting two surveillance tests "HPCI Steam Supply
- Isolation Valve Logic" and "HPCI Injection Valve Logic," at the same tihe, and not ensuring that test prerequisites and initial test conditions for all steps
! in the test procedures were met.
I
{
3-8 9
3.2.1.7 Hatch-2 Event on October 28, 1983 In this incident, the testable check valve in the LPCI line was found open during valve operability test for the RHR system. The failure was due to a I maintenance error committed more than four months previously, on June 7, 1983.
After that maintenance, the two air supply lines from the solenoid operated valve to the air actuator were reversed. This failure was mainly attributed to the failure to use the valve maintenaace manual which was not available at the time. The error was not discovered by post-maintenance testing which was either
- missed or not corr ctly done. During the four month period, the reactor was operating at substantial power levels. The open check valve went undetected by plant personnel even though valve position and actuator travel indications were provided in the control room. This lack of detection is attributed to also
, reversing the electrical leads such that the indication in the control room indicated the valve was closed.
3.2.1.8 Susquehanna Event on May 28, 1984 e
, The incident started with duel indication (i.e., both "open" and " closed"
! indicating lights illuminated) for the testable check valve and its bypass valve in the LPCI line. The inboard injection valve was in its normally closed 4
position. Later, the outboard injection valve was closed, and the inboard injection valve was cycled in an attempt to seal the testable check valve. JUhen the outboard injection valve was reopened, pressure at the primary side of the RHR heat exchanger was observed to be increasing and the outboard injection valve was closed again. . _
The only problem reported for the testable check valve was dual i
indication. It was attributed to a loose diaphragm plate connector that resulted in improper contact with the limit switches in the bypass valve. The plate connector and its set screw were tightened. No other failure modes of the testable check valve were reported. Since the pressure at the RHR heat exchanger was increasing, some leakage through the check valve or its bypass valve must have occurred.
1 I
t i
i -
3-9 The inboard injection valve failed to fully close after being cycled. It was found that the valve disk would not center on its seat due to the dimensions of the disk huidebearingsurface. This resulted in the valve sitting low in the body. .Ehetomachiningtoleranceduringmanufacturing,thediskwouldnot seat in the same location each time it was stroked. The seat was lapped and its lower disc guide bearing surface was built up 1/4".
3.2.1.9 Browns Ferry-1 Event on August 14. 1984 In this incident, the testable check valve failed open due ts maintenance error, and the injection valve was opened inadvertently during the Core Spray System Logic Test. As a result of these failures, low pressure piping and equipment were overpressurized for 13 minutes before the operators reclosed the injection valve.
The check valve failure was caused by maintenance error in installing a plunger with reversed air ports in the actuator pilot solenoid valve.
Maintenance records indicated that the valve was held open from December 1983.
The valve misposition was not detected because the position indication was also reversed following the maintenance such that the valve misposition was not evident.
The injection valve was opened due to operator failure to follow the test procedures. The procedures specified that the valve motor. operator circuit breaker should be racked-out so that the valve would have no motive power and would remain closed during the logic test. However, the operator failed to rack-out the breaker. Thus, when test signal was applied during the logic test, the injection valve opened.
3.2.2 Events Involving Failure of Swing Check Valves The last two incidents in Table 3.2 involve failure of check valves that are not testable. Figure 3.2 shows the structure of a swing check valve. In the Pilgrim incident, the check valve is used as a containment isolation valve inside the drywell for the LPCI line. In the San Onofre incident, check valves
3-10 are used on the discharge side of the feedwater pumps and downstream of the feedwater regulating valves.
- b 3.2.2.1 SadOnofreEventonNovember 21. 1985 In this incident, five check valves failed open, namely, the discharge check valves of two feedwater pumps, and the check valves downstrer.a of the feedwater regulating valves for the three steam generators. When ac power to pne feedwater pump was lost, feedwater from the other feedwater pump backflowed through the failed open discharge check valve to the suction side of the pump, and caused the flash evaporator to rupture. Due to failures of the check valves, three steam generators were blown down through the ruptured flash evaporator. Following the emergency procedures, the operators isolated the feedwater lines. As the auxiliary feedwater system started to fill the emptied feedwater lines, a water hammer occurred and caused a crack on the feedwater line and multiple failures of pipe supports. Throughout the incident, the primary coolant inventory was maintained with charging pumps, and was properly cooled.
The failure modes of the check valves are very similar. Either the disc was separated from the hinge arm or the disc nut was loose. There was evidence indicating that these failures existed over an extended period of time, for example, worn hinge pin hole, damaged disc stud, and scratch marks at the bottom. The cause of failure was attributed to inadequate design, and flow induced vibrations. Check valve failures caused by partial disassembly while in service do not appear to be unique to San Onofre-l.
According to the ASME Boiler and Pressure Vessel Code,Section XI, the feedwater check valves should be tested every cold shutdown if three months has passed since the last test. Records indicated that the feedwater pump discharge check valves were last tested in November 1984, and the feedwater regulating check valves were last tested in February 1985. There were three cold shutdowns s between February 1985 and November 21, 1985 when the incident occurred. The check valves were not tested as required during those shutdowns. Otherwise, the failures might have been discovered before the transient occurred.
1
3-11
- Table 3.3 lists the incidents of failures of feadwater check valves that were identified by LER search" and review of Nuclear Power Experiencel ' (NPE).
Onlythose.lailuresthataresimilartothefailuresatSanOnofre-1arelisted.
3.2.2.2 Pilgrim-1 Event on February 12, 1986 and April 11, 1986
. I j In the incident on February. 12, 1986 both the testable check valve and the I
normally closed LPCI outboard injection valve leaked, resulting in high pressure alarms. The alarms occurred repeatedly in the few weeks before this date.
Operators simply vented the piping after each alarm. On this date, the outboard injection valve was manually tightened, and its torque switch was replaced and I reset. Also, the inboard injection valve was closed. The plant continued power operation until April 11, 1986, when more high pressure alarms occurred. The outboard injection valve started leaking. The plant was shutdown. The cause of [
failures was not reported.
3.3 References
- 1. P. Lam, "Overpressurization of Emergency Core Cooling Systems in Boiling Water Reactors," Nuclear Regulatory Commission Office for the Analyses and Evaluation of Operating Data, February 1985.
- 2. " Trip to Browns Ferry Unit 1 Regarding Potential Core Spray Overpressurization," Memorandum from Scott Newberry to Barry Holahan, Cperating Reactors Assessment Branch, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, September 29, 1984.
- 3. "Overpressurization of Core Spray Piping," LER 84-032, Browns Ferry Unit 1, September 13, 1984
- 5. " Loss of Power and Water Hammer Event at San Onofre Unit 1, November 21, 1985," NUREG-1190, U.S. Nuclear Regulatory Commission, January 1986.
l l
l j
3-12
- 6. " Reactor Shutdown duc to Inoperability of the 'B' Loop of Low Pressure Core Injection," LER 84-006, Susquehanna Unit 2, June 27,1984 E- .
- 7. "Recent Events at ' Pilgrim," Memorandum from Edward L. Jordon, Director of .
Emergency Preparedness and Engineering Response, Office of Inspection and Enforcement, to Robert M. Benero, Director Division of Boiling Water Reactor Licensing, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, May 1986.
- 8. "HPCI System Inoperable," LER 83-048, Pilgrim Unit 1, October 14, 1983.
- 9. "Overpressurization of LPCI Piping," LER 75-24, vermont Yankee, Vermont Yankee Nuclear Power Corporation, January 8,1976.
- 10. " Abnormal Degradation of the Primary Containment Boundary, LER 77-04, Cooper, Nebraska Public Power District, February 4,1977.
- 11. "HPCS Testable Check Valve Failure," LER 82-115, LaSalle Unit 1,
' Commonwealth Edison, November 3,1982.
- 12. "HPCS Testable Check Valve Failure to Close," LER 82-066, LaSalle Unit 1 Commonwealth Edison, July 15, 1983.
- 13. " Inadvertent Draining of RCS Water," LER 83-105, LaSalle Unit 1, Commonwealth Edison, September 27, 1983.
- 14. "Overpressurization of HPCI Piping," LER 83-048, Pilgrim Unit 1, Boston Edison Company, September 30, 1983.
- 15. " Stuck open Isolation Check valve on the Residual Heat Removal System at Hatch Unit 2," AEOD/E414, U.S. Nuclear Regulatory Commission, May 31, 1984.
- 16. Licensee Event Report 83-112/03L-0, Hatch Unit 2, Docket 50-366, Georgia Power Company, November 17, 1983.
^ ,
,f 3-13
- 17. "High Pressura Alarm in LPCI Line," Preliminary Notification of Occurrence, Pilgrim April 11, 1986.
. ta
- 18. "Reacter Tripped due to Loss of Power to Safety Related Buses," I LER-85-17-1, San onofre-1, { November 21, 1985.
- 19. S. M. Stroller Corporation. . Nuclear Power Experience, updated monthly.
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""r R- - Table 3.1 Summary of Operating Events identified In Ref erence 1 Testable Isolation Check Valve Normally Closed injection Valve Event Perc ent System Plant Date Power involved Status Cause Status Cause Overpressurization Vermont Yankee 12/12/75 99 LPCl/RHR Open Unknown Intentional but In- Monthly Testing of Yes LER 75-24 ,
appropriate opening LPCI Cooper 01/21/77 97 HPCI Open Loose Part Obstruction inadvertent Opening Personnel Errors Yes LER 77-04 During HPCI Function-al Test LaSalle-1 10/05/82 20 HPCS Open Dried Lubricant and Closed --
No LER 82-115 Insuf ficient Preload in Air Operator; Opened Dypass Line Lassile-1 06/17/83 48 HPCS Open Thermal Binding; Closed -
No y LER 83-066/03L Opened Bypass Line j m
LaSalle-1 09/14/83 0 LPCI Open Maintenance Errors intent for-t* but In- RHR Relay Logic No, but drained 5,000 LER 83-105/01T appropriate Opening Testing Gallons of RCS Water Pilgrim 09/29/83 98 HPCI Open Rusted Linkage on Air inadvertent Opening Personnel Errors In Yes LER 83-48 Operator IPCI Logic Testing H atc h-2 10/28/83 0 LPCI Open Maintenance Errors on Closed - No l LER 85-112/03L ,
Air Operator Browns Ferry 1 08/14/84 100 LPCS Open Malntenance Errors on inadvertent Opening Personnel Errors In
- Yes LER 84-032 Air Oporator LPCS Logic Testing
r Samunary cf Operr. ting Events isolation Check Valve -
Inboard injection Yalve Event Percent Systen Plcnt Oate Power involved Status Cause Status Cause Overpressurization ,
Verinost Yankee 12/12/75 99 LPCl/RHR
- Unk'nown intentTonal but in- knthly Testing of Yes LER 75-24 appropriate opening LPCI
)
ep .
Cooper 01/21/77 97 HPCI Open Loose Part Obstruction inadvertent Oponing Personnel Errors Yes .* ,
LER 77-04 , Ouring WCl Function-al Test " l LcSalle-1 10/05/82 20 HPCS ** Dried Lubricant and Closed - No LER 82-115 insuf fic ient Preload in Air Operator; Opened Bypass Line l
LaSalle-1 06/17/83 48 WCS ** Thermal Binding; Closed - No LER 83-066/03L Opened Bypass Line LaSclie-1 09/14/93 0 LPCI Open Maintenance Errors Intentional but In- RHR Relay Logic No, but dralned 7,000 LER 83-105/01T appropriate Opening Testing Gallons of RCS Water 4
w Pilgrir,-1 09/29/83 98 HPCI Open Rusted Linkage on Air inadvertent Opening Personnel Errors in Yes LER 83-48 Operator HPCI Logic Testing Hatc h-2 10/28/85 0 LPCI Open Maintenance Errors on Closed - No i LER 83-112/03L Air Operator ,
Susqurhanna-2 05/28/84 2 LPCI Leaked Unknown Leaked Disc Failure to Seat Pressure was increas-LER 84-006 Ing l
Browns Ferry 1 08/14/84 100 LPCS Open Maintenance Errors on inadsertent Opening Personnel Errors in Yes LER 84-032 Air Operator LPCS Logic Testing San Onotre 11/21/85 60 MFW Opon Open- ,
Yes Pilgria 02/12/86 100 LPCI Leaked Unknown Opon --
Yes FDid not seat properly.
s'Fallud to rescat after test.
i Tablo 3,2 (Continxed)
-.m _
Outboard injection Valve
~~
Event Perc ent System Picnt Date Power involved Status Cause Related Surveillance Ref erenc es 12/12/75 99 LPCl/RHR Closed but Unknown Valve Operability Test ,1,9 fermontY1nkee LER 75-24 w .,.,..
Cooper 01/21/77 97 HPCI Open --- IFCI System Turbine Trip and initiation 1,10 LER 77-04 Logic Surveillance Test LES211e-1 10/05/82 20 HPCS -- - HPCS System Quarterly Surveillance 1,11 lER 82-115 A0 Check Vaivo Cy:1Ing Lssalle-1 06/17/83 48 HPCS - --- WCS System Quarterly Operating 1,12 LER 83-066/03L ,' Surveillance LaSalle-1 09/14/83 0 LPCI -- --- RHR System Relay Logic Test 1,13 LER 83-105/01T Pilgrim-1 09/29/83 98 HPCI Open Personnel Error HPCI Injection Valve Logic, HPCI 1,14 y LER 83-48 In Testing Steam Supply isolation Valve Logic 5 listc h-2 10/28/83 0 LPCI -- - RHR Valve Operabillty 1,15,16 LER 83-112/03L Susquohtnne-2 05/28/84 2 LPCl Ven ~~ --- 1-3 LER 84-006 firorns Ferry 1 08/14/84 100 LFCS Open -- Core Spray Logic Test 1,6 LER 84-032 Stn Onofra 11/21/85 60 MF w --- --- ---
.5,18 allgria 02/12/86 100 LPCI Leaked Unknown --- 1,7,17 9
3-19 Table 3.3 Failures of Check Valves in Feedwater Systems I. "
l, -
Plant Date Failure Mode Source Crystal River 3 April 5, 1980 Missing Disc Retainer Pin LER 80-017 Surry 1 April 17, 1980 Dies Detached LER 80-023 Crystal River 3 May 6, 1980 Missing Hinge Pin LER 80-021 Turkey Point 3 April 1, 1981 Missing Disc Stud Nut LER 81-007 Missing Pivot Pins Turkey Point 4 June 8, 1982 Missing Disc Stud Nut LER 81-008 LaSalle 1 October 4, 1984 Hinge Pin Busing Moved Out of Dise LER 84-064 Quad Cities 2 March 18, 1985 Missing Hinge Pin NPE B.14.A.161 Brunswick 2 June 18, 1986 Loose Disc Pivot Pin LER 86-017 d
.g i
4-1 r .
-l-This se tion presents the quantification of the frequency of overpressurization in each of the interfacing lines identified in the analysis documented in Section 2, and the frequency of core damage as a result of the overpressurization. The frequency of overpressurization 'in ECCS injection lines is basically estimated based on the operating event experience and data searches identified in Section 3. Quantification of these events is addressed in Appendix D and summarized in Table 4.1. In each of the operating event incidents, either one or two pressure isolation valves (PIVs) failed. The failure modes and the causes of failures are discussed in Section 3 and Appendix B. Whether or not each identified failure can happen in the interfacing lines
- of this study is specifically considered, taking into account the specific valve arrangement and the test requirements / procedures for each line. If a similar L
failure mode is judged to be credible, then the operating event experience is used to estimate the frequency of failure. When any of the operating event experience is judged not to apply to a given . interfacing line, the failure data from Table 4.1 is used to asses the frequencies of different combinations of PIV
, . failure modes that will lead to overpressurization.
Given that a segment of low pressure piping is overpressurized, then the possibility that a rupture could occur is considered. Figure 4.1 illustrates' the event tree used to determine the conditional probability of various sized LOCAs given that the low pressure piping has been overpressurized. The
- probabilities in the figure apply to the LPCI line at Peach Bottom with the PIVs failed in a Browns Ferry like scenario. Appendix A identifies the valves that i
define the boundary of the pipe sections that could be overpressurized. Based upon layout drawing reviews and site visits, most of the valves and other compone,nts that could be overpressurized are located in the various pump rooms.
The pressure isolation valves are located close to the drywell. Between the PIVs and the pump room is simply pipe runs. The relative vulnerabilities of
, equipment have been arsumed to be pump seals, heat exchangers, and then pipe ;
welds with the lowest failure probability. Therefore, the most likely locations of a rupture or leakage would be in the pump rooms.
d 4-2 The BWR Owner's Group estimated I the conditional probability for BWR ECCS pressure boundary rupture during an overpressurization event to be 3.0x10-5 due to pipe weld failure. BNL was not chartered with verifying this failure probability r with doing an independent analysis. Therefore, sensitivity calculations were performed using a range of three values for probability of rupture; 10-1, 10-3, and 3.0x10-5 Given that the BWR Owners' Group work was focused on pipe welds, it is believed to provide a lower bound for the various ruptures that may occur as discussed above. The upper bound for the rupture failure probability was chosen simply to provide a conservative estimate in the r
expectation that this would bound the actual failure probabilities. '
Given a rupture of low pressure piping, blowdown of reactor ecolant will start. Depending on the initiating failure modes of the PIVs, the blowdown may be able to be terminated without significant loss of reactor coolant inventory.
For example, if the testable check valve has been held open due to the reversal
- of its air supply to the valve operator, the blowdown flow should cause the check valve to close. This is the case because the air operators are
- deliberately designed with insufficient torque to move the valve open given differential pressure across the valve. A failure probability of 0.01 has therefore been assumed for the check valve failure t'o reclose to account for the i possibility that it may be damaged when the disk impacts the seat at high speed. Once a blowdown has started, manual isolation using motor-operated i valves in the line blowing down is not considered credible, because little time is available and the MOVs are not designed to operate under blowdown conditions. Given that the blowdown is not isolated, it is assumed that core
, damage will result due to structural failure, flooding ECCS equipment, and/or
, draining of the suppression pool. This results in sequence 4 in Figure 4.1.
The pump rooms are designed for 0.25 psi pressure differential between the inside and the outside. The ventilation openings for the pump rooms may not be i large enough to rapidly relieve the overpressurization resulting from the j blowdown. Structural failure increases the possible impacts of flooding on systems needed to mitigate the accident. If the break location is at a low 1
elevation, the suppression pool may also be drained.
If no rupture occurs in the overpressurized pipe section, a small loss of coolant accident is assumed to occur, resulting from open relief valves and 4
s 4-3 failure of gaskets. This results in sequence 1 or 2 in Figure 4.1, depending on the operator's ability to isolation the line. In most cases, such small LOCAs can be isolaked with the PIVs in the line. The time available for the operator to isolate a [smallLOCAisestimatedtobemorethan30minutesbaseduponcore -
uncovery (Ref. 2). Figure 4.2 taken from Ref. 3 shows some time curves for operator actions. The curve for the NREP cognitive error is used to assess the probability that the operators fail to isolate the small LOCA. It is approximately 10-2 at 30 minutes. If the break is not isolated, the small LOCA eve.nt tree in Figure 4.3 is used to assess the conditional probability of core damage. This event tree is a modified version of the small LOCA event tree in Ref. 4. The probabilities used in the figure apply to a small LOCA in the RHR room of Peach Bottom.
Basically, the small LOCA event tree in Figure 4.3 examines the systems that can be used to provide makeup to the reactor. First, high head systems are considered. If at least one high head system is available, the operators need to depressurize to reduce the flow through the break and use the low pressure systems to provide coolant makeup. If no high head system is available, the automatic depressurization system should depressurize the system, or the operators need to manually depressurize the system, so that low pressure systems I
can be used. It is assumed that the ECCS injection loop in which the small LOCA occurs is unavailable.
The pump rooms are water tight up to approximately 20 feet above the floor and are equipped with floor drains or floor drain pumps. For the RHR pump room at Peach Bottom, it is estimated that it will take approximately two hours for a f
small LOCA with a leakage rate of 600 gpm to fill the room to the level of the ventilation openings. Therefore, tt will be more than two hours before the flooding encroaches upon other ECCS areas. By then, the reactor should have been depressurized. Appendix A lists various indications of interfacing LOCA available to the operators. If they recognize that an interfacing LOCA has taken place, they will depressurize the primary coolant system to reduce the leakage and to preserve sources of makeup the primary coolant system. With more than two hours available, the time curve in Figure 4.2 for NREP cognitive error is used to assess the probability that the operators fail to depressurize the primary coolant system. It is approximately 5x10-4 at two hours. It is
- g. - .- - . - . . . . . . - - - . -._
4-4 i
conservatively assumed that if the operators fail to depressurize in two hours, all ECCS are disabled due to flooding. This results in sequence 4 or 5 and sequence 9.hr'10inFigure4.3. A probability of 5x10-2 is used in the event tree for op rator failure to depressurize, because this event tree is I conditional on the event that the operators have already failed to isolate the 1
small LOCA, that is, 4
P(failure to depressurize failure to isolate)
= P(failure to depressurize and failure to isolate)
/P(failure to isolate)
= 5x10-"/10-2
= 5x10-2 4
i 1
It is also assumed that if the primary system is depressurized in two hours, no other ECCS system will be affected by the LOCA, except that RCIC and HPCI may be isolated due to high room temperature caused by steam that may go from the location of the LOCA to the RCIC or HPCI pump room through ventilation ducts.
j For screening purposes, it is assumed that if the operators fail to isolate the small LOCA in 30 minutes, RCIC and HPCI will be isolated by high pump room l . temperature. It can be seen from Figure 4.3 that the dominant core damage scenario for a small LOCA in due to failure of the operators to depressurize the primary system such that ECCSs are disabled due to flooding. The assessment of the unavailabilities of the systems in Figure 4.3 is described as follows.
l
, . FW - The unavailability of feedwater system is based on the analysis of Ref. 5, where an event tree analysis for the availability of the j feedwater system and the power conversion system given an inadvertent l opening of relief valve is performed.
. HPCI & RCIC - Both systems are assumed unavailable due to steam induced isolation.
. ADS - The unavailability is based on the result of BNL reviews og Shoreham PRA.
1 4-5 i e
LPCI & LPCS - Based on the result of BNL reviews of Shoreham PRA, the unavailabilities of LPCI and LPCS are 2.7x10-3 and 3.6x10-3, respbtively. The unavailability of both systems is 6.2x10-4 Since one' loop pf LPCI is assumed unavailable, the unavailability of both systems j*
should be between 3.6x10-3 and 6.2x10-4 1.0x10-3 is used in the f I
analysis.
- Condensate Pump - The unavailability is based on Ref. 5. It represents human error in controlling condensate injection.
As noted above, the event tree and failure probabilities in Figure 4.3 apply specifically to either of the two LPCI injection lines. As each similar ,
line is analyzed, the interfacing LOCA induced system unavailabilities pertinent to that line are substituted for those shown on Figure 4.3. These interfacing line specific failure probabilities are listed in Table 4.1A. Sections 4.1 to 4.3 provide detailed line by line analyses for the three representative plants.
The overall resalts for the three plants are summarized in Table 4.2.
, 4.1 Frequency of Core Damage for Peach Bottom I
I i l In this section, the interfacing lines identified in Section 2 for Peach Bottom are analyzed one by one. Frequency estimates are made based on operating l
event experience, current data searches, and where necessary, already published generic data. First, the test requirements for the PIVs'are discussed and their effect on valve unavailability is considered. Then, a line by line analysis.of
[ each interfacing line is presented. Detailed descriptions are provided for the i
j LPCI injection lines. For lines that are similar to LPCI, only the differences are discussed and the effects on the calculated results are provided. Table 4.3 summarizes the line by line results for the Peach Bottom plant. -
L l
4.1.1 Test Requirements for Pressure Isolation Valves '
4.1.1.1 Operational Hydrostatic Test
( This test is done before startup after refueling. The reactor pressure
- vessel is filled, and pressurized to 1000 psig. Leakage through the PIVs is 1
(
i
7, ~
4-6 measured by opening test taps downstream of the valves. Table 4.4 lists the PIVs tested and the success criteria used.
.b 4.1.1.2 Lo e System Functional Test l
This test is done every six months on ECCS systems. It can be done at shutdown or at power. The test; procedures for the RHR and core spray systems require that a relay be energized to inhibit the "open" signal to the normally
, closed injection valve before an actuation signal is generated. The test engineer is required to initial this step in the procedure after it is performed ~. If this step is skipped, due to human error, the injection valve
- will be. inadvertently opened. Given that the valve is inadvertently opened, the operator can manually reclose it or close the normally open injection valve.
The test procedure also requires verification of injection valve position af ter the actuation signal is simulated. As far as the inadvertent opening of the l injection valve is concerned, the test procedures for HPCI and RCIC are similar to those for the RHR and core spray, except that for HPCI the normally open injection valve is kept closed with a discharge valve override switch, and the normally closed injection valve is opened when the simulated actuation signal is
- a logic system functional test is expected to cause injection to the vessel, not interfacing system LOCA. However, as part of the test, a high drywell pressure signal is generated after an isolation signal is inserted and has not been reset. This will cause the injection valves to open with the pump not running, if the signal to the outboard injection valve is not blocked. Therefore, inadvertent opening of the injection valve may lead to an overpressurization of the suction side of the pump. '
4.1.1.3 Local Leak Rate Test (LLRT) 4 This is the type "C" test for containment isolation valves defined and discussed in Appendix J to 10CFR50. The valves in the interfacing lines that are subject to this test are the injection valves in the ECCS systems, the RHR shutdown cooling suction valves, the MOVs in vessel head spray line, and the feedwater check valves outside the drywell. The testable air operated check valves are not required to undergo type C tests. This test is required to be
,--y- - -- ,,,-----r.,,,-,
4-7 performed once every operating cycle, in no case at intervals greater than two years. Typically, the test is done by pressurizing a test volume using service air, so thatIthe valve or valves being tested define the test boundary. The test pressur across the valve is 49.2 psid and the leakage is established by
- measuring the flow needed to maintain the pressure. The success criteria is specified in terms of aggregate leakage through all containment isolation valves and all containment penetrations.- The total leakage rate can not exceed 60% of the maximum allowable leakage rate at the calculated peak containment internal pressure related to the design basis accident. Although no success criteria is specified for individual valves, excessive leakage is expected to be detected during LLRT, because each individual leakage rate is recorded. '
4.1.1.4 Valve Functional Test The injection valves of the ECCS systems are stroke tested monthly. Each valve is stroked with the other injection valve closed. The stroke time is recorded. When testing the in,'ection valves in the RHR or core spray system when the reactor pressure is greater than 100 psig, the bypass valve for the testable check valve is opened and the pipe section between the injection valves is pressurized by n N2 bottle to reduce the pressure differential across the inboard injection valve. The opening and closing currents for the motor operators are also taken. The testable check valves are cycled only during a shutdown greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or after valve maintenance.
4.1.2 LPCI Injection Line Quantitative analysis for the LPCI injection lines is described in detail in this section and summarized in Table 4.5. The valve arrangement in this line consists of a testable check valve, a normally closed MOV and a normally open MOV. The testable check valve is leak rate tested at 1000 psig during the operational hydrostatic test at every refueling, and is cycled every shutdown greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Since the testable check valve is not leak tested after maintenance, the same failure that occurred at Brown's Ferry-1 and Hatch-2 may occur without detection, i.e., reversal of air flow and position indication.
The frequency for such failure can be estimated based on two events in 1361 valve years, i.e., 2/1361 - 1.47x10-3/ year.
4-8 l
Given that the testable check valve is held open due to air reversal, the normally closed MOV is pressurized, the MOV may fail open due to valve rupture, failuretofblyreclosefollowingasubsequentcycling,orinadvertent opening. ThhMOViscycledeverymonth,localleakratetestedand I hydrostatically tested every refueling. Given that the check valve is held'open by the air operator after maintenance, the expected number of months before refueling is approximately six (one half an assumed yearly refueling cycle).
4 The MOV is not designed to operate with the differential pressure across the valve close to the reactor pressure. To cycle the valve, first the normally
, open injection valve is closed, and the bypass valve around the testable check valve is opened, so that the inboard MOV is pressurized at the vessel side, then a nitrogen bottle is used to pressurize the pipe section between the two injection valves so that the pressure across the inboard MOV is less than 100 psi. If the outboard MOV fails to close fully, the operators will have problem pressurizing the pipe section. Therefore, the failure will be discovered.
Af ter cycling the inboard injection valve, the operator needs to drain the pipe section between the two injection valves, before the outboard injection valve is reopened, If the inboard injection valve fails to fully reclose, the operator l
will have a problem draining the pipe section. Therefore, the failure will be
- discovered. If the operator skips this draining step in the procedure, then the
- failure may go undetected. A human error probability of 3x10-3 is used for this operator error. Therefore, the probability that the MOV fails to fully reclose and the failure goes undetected is i 1.07x10-"/ demand
- 6 demand
- 3x10-3 = 1.93x10-6, where the probability of valve failure is taken from Table 4.1. Similarly, the probability that rupture occurs is
[
l
! 1.2x10-3/ry
- 0.5 ry = 6.0x10-4, where the failure rate for MOV rupture is derived in Appendix D.
Inadvertent opening of the MOV will occur if the operator misses a step in the six month logic system functional test. A human error probability of 3x10-3 e
u .__ .- , - - - . . _ , , . ,_ _ , , - , , - - - - . ~ . - - - .
4-9 '
is used for such failure. It is taken from Table 20.7 of the Human Reliability Handbook.6 h.
Another failure mode of the MOV is that the MOV is opened by a spurious signal generated by human errors during testing or maintenance, or hardware failures in its control logic. This is indicated as MOV " transfer open" in Table 4.5. The failure rate, 8.1x10-4, is taken from Table 4.1.
.Since that the scenario of the Browns Ferry-1 event is judged to be credible for Peach Bottom, the frequency of the scenario is estimated to be one event in 1361 years, i.e., 7.35x10-" per reactor year.
The frequency of overpressurization in this LPCI line based on the experience at Browns Ferry-1 and Hatch-2 is 1.47x10-3 x (1.93x10-6 + 6.0x10-" + 3.00x10-3 + 4.05x10-") + 7.35x10-"
= 7.41x10-".
. .To determine the frequency of LOCA in such scenario, the specific cause of MOV failure needs to be considered. If the MOV failed to fully reclose af ter being cycled open, the flow through the valve is assumed to be limited by the
[ . gap between the disc and the seat. It will lift the relief valves, but will not necessarily cause a rupture to occur. Such a LOCA can be isolated by closing the normally open MOV. As was discussed earlier,10-2 is used for the f
h probability of failure to manually isolate. Therefore, the frequency of an unisolated small LOCA due to reversed air supply for the testable check valve
[ and the failure of the MOV to fully close after being cycled is I
1.47x10-3 x 1.93x10-6 x 0.01 - 2.83x10-II/yr.
7 In the case of MOV rupture or inadvertent opening, the MOV is widely open. ,
Therefore, a rupture of low pressure piping is possible. The event tree in Figure 4.1 can be used to estimate the frequency of LOCA. If a pipe rupture occurs, the blowdown will cause the testable check valve to close. As was discussed earlier, 0.01 is used for the probability of failure for the check valve to close. If the check valve does close, it is assumed that a small LOCA
4-10 results due to open relief valves. Such a small LOCA can be manually isolated with failure probability 10-2 If the check valve fails to close, it is assumed thatalargeI.LOCAresults. The frequency of a large LOCA due to reversed air supplytothhtestablecheckvalveandruptureofMOVis '
1.47x10-3 x 6.0x10-4 x 10-3 x 0.01 = 8.82x10-12/yr.
For illustration purposes, 10-3 is used here for the probability of pipe rupture. Similarly, the contribution due to inadvertent opening of the MOV is 1.47x10-3 x 3x10-3 x 10-3 x 0.01 = 4.41x10-II/yr, the contribution due to transfer opening of the MOV is 1.47x10-3 x 4.05x10-4 x 10-3 x 0.01 = 5.95x10- 12/yr, and the contribution due to the Browns Ferry scenario is 7.35x10-"
- 10-3
- 0.01 = 7.35x10-9/ry.
. The frequency of a small LOCA due to reversed air supply to the testable check valve and rupture of MOV is 1.47x10-3 x 6.0x10-" x [(1-10-3)x10-2+10- 3x9.9x10-3] = 8.82x10-9/yr.
Similar contribution due to inadvertent opening is 1.47x10-3 x 3x10-3 [(1-10-3)x10-2+1o-3x9.9x10-3] = 4.41x10-8, The contribution due to transfer opening is 1.47x10-3 x 4.05x10-" [(1-10-3) x 10-2 + 10-3 x 9.9x10-3] = 5.95x10-9 l
The contribution of the Browns Ferry scenario i5 l 7.35x10-4 * [ ( 1 3)
- 10- 2410-3
- 9.9x10-3)] = 7.35x10-6/ry.
1
4-11 h
t Table 4.5 summarizes the calculations described above based upon the incidents that occurred at Browns Ferry and Hatch-2. It also shows the calculations done based upon: he other operating event experience.
( :
The Cooper incident is similar to the Browns Ferry-1 incident, except that the testable check valve was held open by a broken sample probe. The effect of this failure mode is that if a blowdown occurs, the check valve will not be able to reclose. In case of a small LOCA, isolation can be carried out using the normally open MOV. The Pilgrim incident on September 29, 1983 is also similar to the Browns Ferry-1 incident in that the check valve was held open. The difference is that the testable check valve was partially open due to rusted
- linkage between the valve stem and the air operator. The check valve should be able to close when a blowdown occurs resulting from the pipe rupture. The failure probability is again assumed to be 10-2 for this failure mode.
The rest of the operating experience involving testable check valve failures did not result in overpressurization. These check valve failure incidents have been used to estimate the frequency of check valve failure. In the event at LaSalle-1 on September 14, 1983, the testable check valve was 35' open due to misalignment of interfacing gears and tight packing gland. Based on the description of the LER, the air operator inhibited motion in the closed direction. Therefore, this in.cident is analyzed in the same way the Browns Ferry-1 incident was analyzed, except that the check valve is not expected to close when a blowdown occurs. The remaining incidents in Table 4.5 involve leakage through the testable check valve. They are used to estimate the frequency of check valve leakage. If the MOV also fails open, the leakage is assumed limited by the check valve. Therefore, only a small LOCA is postulated
- to result.
1 The results of the above calculation are summarized in Table 4.5.
4.1.3 Core Spray Injection Lines
, The Peach Bottom core spray injection lines have the same valve arrangement
- and the same test requirements as the LPCI lines. The only difference considered here is that core spray injection lines have their own injection
4-12 nozzles at the spray spargers in the vessel. The chance that any foreign material will go through the piping inside the vessel and reach the core spray testablechdekvalvesisnegligible. Therefore, incidents like that which occurred at booperarenotconsideredcrediblefortheselines. This makes the frequencies listed in Table 4.3 for core spray lower than those for LPCI.
1 These lines differ from LPCI in the following ways:
- a. An additional check valve in the feedwater line needs to fail open to result in a LOCA. If both the testable check valve and the normally closed MOV fail open, an overpressurization will occur. This may cause a transient that leads to feedwater pump trip. However, no LOCA will occur unless the check valve in the feedwater line also fails open. To account for this, a failure probability of 10-2 is used for.the check valve when a low pressure pipe rupture occurs.
- b. The testable check valves in the HPCI and RCIC lines were not hydrostatically tested in the first ten years of operation. This is assumed to directly increase the yearly frequency of testable check valve failure by a factor of ten.
- c. The Pilgrim event on September 29, 1983, in which the air operated L check valve was opened due to a rusted linkage between the valve stem t
and the attached air operator and the two discharge MOVs were
- simultaneously opened as a result of human errors in testing the HPCI injection valve logic and steam supply isolation valve logic, is judged to be credible for the HPCI and RCIC lines at Peach Bottom, because similar tests are also performed. This experience is used to estimate the frequency of this scenario of overpressurization.
- The calculations for these lines are shown in Table 4.6.
f d
S
,7 - - , - . _ - - , , , - - - - - - - , , --- -- - - - -
l 4-13 4.1.5 Feedwater Line ThemosknotableoperatingexperienceassociatedwiththislineistheSan Onofre-1inchdent.The frequency for common cause failure of check valves in .'
the feedwater line is estimated using the evidence of this one event in approximately 1000 reactor years as simply 10~3 per reactor year. For this particular event, this is also the frequency of overpressurization.
Based on the general arrangement plan in the Peach Bottom FSAR, feedwater heaters #3 and #4 (at level 135') are physically close to the battery rooms and the emergency switch gear rooms. These rooms may be affected by blowdown through a ruptured feedwater heater. The general arrangement plan shows that the heaters are inside their own compartments each with two doors. BNL was unable to enter these compartments during the site visit but was informed by Philadelphia Electric Company that the feedwater heater compartments are open at the ceiling. Therefore, overpressurization failure of any building structures is not expected to occur. Based on a tour of the turbine building, the 135' level is generally a big open area, with a large open floor area that connects this level to several lower levels. Therefore, flooding of this level can not exceed the height of the curb (approximately six inches). Equipment inside the switchgear rooms is at least one foot above the floor. Based upon drawing reviews and the site visits, it is assumed that ECCS systems are not affected by I a rupture of a feedwater heater.
ASEP analysis for Peach Bottom assessed the unavailability of ECCS during a i large LOCA to be 1.24x10-4 If an ECCS system is available, the operator still l needs to isolate the break to stop the loss of coolant inventory to outside the
! containment, or provide makeup from sources outside the containment. There are MOVs in the feedwater line that can be used to isolate a feedwater heater rupture. The condensate storage tank and high pressure service water systems can be used to provide makeup. The primary system coolant inventory is approximately 165,000 gallons. The volume of the water in the suppression pool is approximately 475,000 gallons. When a large LOCA occurs, the ECC systems will reflood the vessel. After reflooding, there should be more than 700,000 gallons of water in the suppression pool. Assuming the break is not isolated I
,y -,m- - - , , , , , , , - , , - - - - +
4-14 and that the operator keeps one LPCI pump running at its capacity of 10,000 gpm, it will take more than an hour before the suppression pool water is exhausted.
ThisdefinesIthetimeavailableforoperatoractions. The probability that the operators fa 1 to carry out the needed action within the hour is assessed to be -
10-3 using the NREP time curve in Figure 4.2.
4.1.6 RHR Suction From Recirculation The two MOVs in this line are cycled every shutdown greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
They are also local leak rate tested and hydrostatically tested every refueling. No operating event experience of overpressurization has been observed for this line. Therefore, the failure rates in Table 4.1 have been used to analyze the frequency of overpressurization. Two modes of failure are considered, failure to fully reclose after being cycled (leak), and valve rupture. Given that there are two valves and two failure modes, four combinations of failures are possible.
- a. Rupture-Rupture - It is assumed that the reactor is shutdown once e'very three months and any valve rupture will be discovered by cycling. It is also assumed that the outboard MOV is pressurized only after the inboard MOV has ruptured. The frequency of this failure combination for each three month period is
-6 22 AT 2.06x10 x (L)2 12 2
L,
= 6.44x10-8 ,
where 2.06x10-6 is the mean of A2 derived in Appendix D.
For one year, the frequency is 2.58x10-7/ry. This is a failure mode that can not be isolated.
- b. Leak-Leak - During each quarterly stroking of the MOVs, each valve has a probability of 6.4x10-3 to fail to fully close. If both valves fail to fully close, the failure is expected to be recognized during plant
4-15 heatup and corrected. Therefore, such failure mode is not further censidered.
- k.
- c. Leh -Rupture or Rupture-Leak - These combinations also lead to small LOCA. The frequency can be estimated by P(failure to reclose) x .8 strokes /ry
- ARupture
- 6 months
= 5.14x10-7/ry. ,
4.1.7 Vessel Head Spray This line differs from the RHR shutdown cooling suction in that an additional check valve failure is needed to cause an overpressurization. This check valve performs the same function as the air operated check valves in t' injection lines of ECSS. Therefore, the failure experience for air operated I- check valves also applies to the check valve, with the exception of those failures that involve air operators. Four events of air operated check valve
. failures in Table 3.2 are not related to the air operator. Therefore, the
- failure rate of the check valve is estimated to be four events in 1361 years, i.e., 2.94x10-3 per year.- Since the check valve is not tested in any way. The average probability over 40 years that the check valve is in a failed state is l 2.94x10-3 per year
- 40 years /2 - 5.88x10-2, ,
l Therefore, this has simply been applied as a multiplicative factor to the results for the RHR suction line.
f i 4.2 Frequency of Core' Damage for Nine Mile Point-2 i
! Similar to the analysis for Peach Bottom, operating experience and generic data have been used to assess the frequency of overpressurization. The test requirements for the PIVs at NMP-2 differ from those already discussed for Peach Bottom. This leads to significant difference in quantitative results for the ECCS injection lines. For example, NMP-2 performs type "C" leak rate test and
. PIV leak rate testing af ter maintenance of the testable check valves.
! Therefore, if the testable check valve is held open by the air operator due to i
_ . _ - - - - , _ _ . ~ . _ _ _ . _ _ - - - _ _ _ . . _ _ _ _ _ _ _ _
~~
4-16 reversal of air supply during maintenance, the failure will be detected by the leak rate tests. Section 4.2.1 describes test requirements for the PIVs and theimpact:Intheuseofoperatingeventexperienceinthequantitative analysis. - ther sections provide line by line analysis. Table 4.7 summarizes
- the calculations for all of the interfacing line at Nine Mile Point-2.
l 4.2.1 Test Requirements for Pressure Isolation Valves 4.2.1.1 Pressure Isolation Valve Leak Rate Test This test is done by pressurizing the pipe section downstream of the PlV being tested to between 1000 and 1040 psig, using a test pump. The test pump 4 takes suction from a 50 gallon container. The decrease of water level in the j container over five minutes is used to calculate the leakage rate. Table 4.8 lists the PIVs and the applicable test success criteria. These tests are performed once every operating cycle at refueling or cold shutdown and after maintenance.
4.2.1.2 Valve Operability Test PIVs are required to be cycled at cold shutdown if not cycled in the past
, 92 days, except valves in the RHR steam condensing line that may be cycled when i reactor is at power. PIVs F052 and F218 in the RHR steam condensing line are required to be cycled every 92 days. Valve cycling is done from the control room, by turning the switch for the valve being tested and watching the valve position indication. PIV F087 is cycled when the high/ low pressure interface interlock is calibrated once a cycle.
4.2.1.3 Local Leak Rate Test The test method has been described in Section 4.1.1.3. The test pressure at NMP-2 is 40 psig. All PIVs in the lines listed in Table 4.7, except valves in the RHR steam condensing line, are also containment isolation valves and, therefore, are subject to LLRT requirements. The LLRT test frequency is once every 24 months. - The testable check valves also undergo LLRT af ter maintenance. Therefore, if the air supply to the check valve is reversed, it can be discovered in the post maintenance test.
4-17 4.2.1.4 Automatic-Actuation Test Per th,eI. Technical Specifications, NMP-2 is required to perform automatic actuationtehtingonthe ECCS once every 18 months. This, test is not performed : '
when the reactor is at power. ECCS actuation instrumentation response time is tested during hot shutdown, cold shutdown or refueling ECCS response time is tested during cold shutdown or refueling. Therefore, yhen the reactor is operating, the failure mode of inadvertent opening of injection valves caused by human error during such tests is not considered.
4.2.2 LPCI Injection Lines The valve arrangement in these lines consists of a testable check valve and a normally closed MOV. They are local leak rate tested and PIV leak rate tested once every 18 months. They are also cycled at every cold shutdown if they have not been cycled in tha past 92 days.
The approach used in the quantitative analysis for these interfacing lines is similar to that for LPCI of Peach Bottom. The following describes the difference between the two:
- a. NMP-2 does not cycle the PIVs in the LPCI lines when the reactor is at power. It is assumed for this analysis that the injection valve is cycled once every three months at cold shutdown.
- b. NMP-2performsLLRTandP1Vleakratetestingafbertestablecheck valve maintenance. Therefore, it has been assumed that a failure mode similar to the air reversal that happened at Browns Ferry-1 and Hatch-2 will be detected during the post maintenance leak tests. For the same I
reason, the failure mode of misalignment after maintenance like that happened at LaSalle-1 can also be detected.
- c. No auto actuation test is performed at NMP-2 when the reactor is operating. Therefore, the failure mode of inadvertent opening during
- such testing is not considered.
l i
- . _ . - - ,_ ~-._-m-.- , , , . , . .,--, --
r., ,, --,-7..,7--,..--.,-.-_,-,,--,,w-,c-w,m. , e--,r,- _ - - - -- - - - - - , - - ~ -- - , .
4-18
- d. NMP-2 has only one MOV in each LPCI line, therefore, if a small LOCA occurs due to MOV rupture, it has been assumed to be impossible for the ope rator to isolate it.
rooms. Therefore, in the modelling, when a small LOCA is assumed to occur in one of the RHR-rooms, RCIC is also assumed to be unavailable to mitigate the incident.
Figure 4.5 is the small LOCA event tree for the NMP-2 LPCI injection line for the rupture failure mode of the MOV. The unavailability of RCIC is 1.0 based upon the discussion above. The unavailability of the low pressure systems is estimated based on the number of loops available. For example, similar to Peach Bottom, 10-3 is used in sequence 16 of Figure 4.5, because two LPCI loops and the LPCS loop are available. When all three LPCI loops and the LPCS loop are available, 6.2x10-" is used. This is taken from BNL review of the Shoreham PRA,5 1.e., the unavailability of both LPCI AND LPCS. The unavailability of HPCS is taken from RSSMAP Grand Gulf.8 The first three branches for the top event "X" in Figure 4.5 represent human error in depressurization given that a high head system is available. It is similar to the same event in Figure 4.3 for Peach Bottom, except that it is not conditional on operator error in isolating the break. Because the MOV is assumed to be ruptured, and no other valve is available for isolation. The failure probability for this event is 3
! based on the NREP time curve at two hours.
Table 4.9 summarizes the calculation for LPCI lines.
I 4.2.3 LPCS Injection Line l
This line is identical to the NMP-2 LPCI injection lines described above, except that the testable check valve failure due to foreign material is not considered credible on the same basis as described previously for the Peach Bottom core spray system.
. , _ - - - , - --y
4-19 4.2.4 Shutdown Cooling Return to Recirculation These, kines are treated identically to the LPCI injection lines described above.
f .
4.2.5 HPCS Injection Line This line is similar to the LPCS injection line, except that the HPCS pump discharge is high pressure. Therefore, the pump discharge check valve must also fail, in order to result in overpressurization of the low pressure portions of the system. Two failure modes of the pump discharge check valve are considered, leakage and rupture. It is assumed that check valve leakage can not be detected. Appendix D discusses the sources of the failure rates for the check valves. Therefore, the probability that the check valve is leaking when the PIVs in this line fail open is 2.94x10-3/ry x 40ry + 2 = 5.88x10-2, Pump discharge check valve rupture can occur only af ter it is pressurized. It is has been assumed that if both PIVs in this line fail open, the time at which~
the failures occur will be in the middle of the year, i.e., the check valve is l pressurized for six months. Therefore, the probability that rupture occurs in' six months is 8.8x10-"/ry x 0.5 = 4.4x10-4 f
Table 4.10 summarizes the calculation for this line.
4.2.6 Vessel Head Spray Line i
The vessel head spray line is connected with both RCIC and RHR loop B. Two testable check valves are used as containment isolation valves. They are local leak rate tested and PIV leak rate tested every 18 months. They are also cycled at every cold shutdown if not cycled in the past 92 days. Two failure modes are considered applicable to these valves, i.e., leak and stuck open due to rusted linkage simila" to that which happened at Pilgrim on September 29, 1983. The i
4-20 failure rates based on this experience are estimated to be Ag - 2.94x10-3/ry and A2 - 7.35x10-"/ry, respectively. Four combinations failures of the two testable che k valves are possible. Their frequencies per year are:
k
- 2 2 A
E* 2 '
2 , and y .
They are listed in Table 4.11. The squares of the failure rates are calculated
'in Appendix D to be the mean of the squares of the failure rates. The first three combinations can only result in leakage, because at least one valve is only leaking. The last combination may lead to a large LOCA.
Outside the tantainment, the vessel head spray line is connected with RCIC and RHR loop B. In the RCIC line, there is a normally closed MOV which is local leak rate tested and cycled at each cold shutdown if not cycled in the past 92 days. In the RHR loop B, there is a check valve as well as a normally closed MOV. The MOV in the RHR loop B is subject to PIV leak test in addition to those tests required for the MOV in the RCIC line. Therefore, the dominant overpressurization path is the RCIC injection line due to the fewer valves required to fail to result in an overpressurization. Failure modes assumed for the MOV in the RCIC injection line are shown in Table 4.11. During RCIC system functional testing (which is required to be performed once every 18 months'when the reactor is either operating or at hot standby) this MOV is opened.
Therefore, a probability of 0.5 is used for the event that the system functional test is performed after the testable check valve failures occur and before the l next local leak rate test is performed on the check valves.
l 4.2.7 Feedwater Line I
The analysis for this line is the same as that for Peach Bottom feedwater lines. Based on the information provided by Nine Mile Point 2 and a plant visit, the only safety related equipment in the turbine building at NMP-2 is some instrument rack related to MSIV. The feedwater heaters at NMP-2 are open to the large volume of the general area inside the building. If a blowdown should occur at a feedwater heater, the flood will have to fill a large volume
4-21 in the pipe tunnel undernaath the heater bay before it can overflow and threaten the service water system. Therefore, it has been assumed that the blowdown does not affect:s stems needed to mitigate the accident.
4.2.8 shutdown Cooling Suction Line The valve arrangement and test requirements for this line at NMP-2 are very similar to that at Peach Bottom. The same quantified results are used.
4.2.9 Steam Condensing Line to RHR Heat Exchanger This line is connected to the RCIC steam supply line outside the containment and feeds directly to the RHR heat exchanger. The RCIC steam line has two normally open containment isolation valves. The steam condensing line is normally pressurized up to the first barrier that consists of two MOVs in parallel, F052 and its one-inch bypass valve F218. They are PIV leak tested once every 18 months and cycled once every 92 days. The second barrier also consists of two MOVs in parallel, F051 and F087. They are PIV leak tested once every 18 months. During calibration of interlocks on the PIVs, valve F087 is also cycled. The frequency of calibration is once every 18 months.
i Failures of the following pairs of valves will lead to overpressurization:
i F052 and F051, F052 and F087, F218 and F051, and F218 and F087. Due to
- the similarity in the calculation of the frequency of overpressurization only
. one pair, F052 and F087, is discussed in detail. The difference between this
, pair of valves and other pairs is also provided. Table 4.12 summarizes calculations for all above pairs of valves.
- F052 is cycled four times a year. If 7087 fails open when F052 is opened, then an overpressurization will occur. The possible failure modes of F087 are
. rupture and transfer opening. Assuming F087 can rupture only if it is pressurized, and that F052 is opened for ten minutes, the probability of F087 rupture is I 1.2x10-3/ry x 10/1440x365 = 2.28x10-8,
4-22 Given an overpresrurization, the analysis is the same as that for other lines.
In the case of a small LOCA, it is assumed that the probability of failure of isolationisI2.Ost10-3 which is the probability used in Ref. 5 for common mode failureofbhthisolationvalves. I Two other failure modes for F052, rupture, is analyzed in the same way.
They are analyzed in the same way. An additional failure mode for F087 is that it is opened when the interlock is calibrated. A probability of 0.5 is used based on the probability that the test comes after the failure. This scenario turns out to be the dominant contributor to core damage frequency.
The pair F218 and F087 is identical to the pair F052 and F087, except that F218 is a one-inch valve. It is assumed that only a small LOCA may result if both F218 and F087 fail open. The pair F052 and F051 is identical to the pair
'F052 and F087, except that no interlock calibration is performed on valve F051.
The pair F218 and F051 is identical to the pair F218 and F087, except that no interlock calibration'is performed on F051.
4.3 ' Frequency of Core Damage for Quad Cities The interfacing lines and their valve arrangements at Quad Cities are also very similar to those at Peach Bottom. The test requirements on the pressure i
isolation valves, however, are significantly different. Section 4.3.1 discusses the current test requirements on the PIVs. The following discussion provides the major differences between Quad Cities and Peach Bottom:
f
- a. Quad Cities has one additional check valve in the feedwater line downstream of both HPCI and RCIC injection lines. This affects the analysis of RCIC and HPCI lines. When a pipe rupture occurs in these l lines, this additional check valve should also close and terminate the blowdown. As opposed to the analysis for Peach Bottom, a probability of 10-3 has been used for the common mode failure of both valves to j close. This reduces the frequencies for large LOCA and core damage in both the.HPCI and RCIC lines by an order of magnitude.
I l
l
~ - .
4-23
- b. The RCIC system at Quad Cities is located in the train B core spray ,
pump room. This affects the calculation in that if a small LOCA occurs in khe train B core spray room, the RCIC system will also be-
- unahailable. Althoegh the converse situation could also hold true, I i.e., that the train B core spray could be rendered unavailable by a -
LOCA in the RCIC, it does not alter the quantitative results as a small LOCA is considered to be isolated by at least one of the three RCIC check valves and for a large LOCA, core damage is postulated directly.
- c. Quad Cites is not required to perform PIV leak rate testing on any PIVs. The testable check valves are not local leak rate tested either. Therefore, if a testable check valve is opened due to reversal of the air supply and the position indication is also reversed as in
+
the Browns Ferry and Hatch events, the failure will go undetected.
- d. Quad Cities just recently installed a safe shutdown system which
] discharges to the discharge line of HPCI. It operates in the same way
- as RCIC except that it has a motor-driven pump instead of a turbine-driven pump. The effect of this additional high head pump on the conditional probability of core damage, given a small LOCA, is that the unavailability of the high head systems is decreased. The effect on the frequency of interfacing LOCA is small because the low pressure portion of the system is separated from the RPV by seven valves in series including check, motor operated gate, and motor operated globe valves.
I r e. The crosstie between the two LPCI loops at Quad Cities is normally
(
open. Therefore, if the PIVs in one LPCI loop fail open, both loops
! will experience overpressurization. It is assumed that if a small LOCA results from the overpressurization, both loops of LPCI are unavailable.
- f. Quad Cities does not perform auto actuation logic testing of ECCS systems when the reactor is at power. Therefore, the failure mode of inadvertently opening an MOV during logic testing while at power is not considered.
' 4-24 The quantitative analysis for Quad Cities is similar to that for Peach Bottom. .Line by line analysis is provided in Sections 4.3.2 to 4.3.6. Table 4.13sumberizestheresultsforQuadCities.
4.3.1 Test Requirements for Pressure Isolation Valves 4.3.1.1 Pressure Isolation Valve Leak Rate Test No PIV leak rate test is required for Quad Cities.
4.3.1.2 Valve Operability Test Injection valves in ECCS systems are stroked once every month. this is done by first closing the other injection valve in the line and then stroking the valve being tested. No pressure equalization across the valve is needed.
Valve timing is performed every three months. Isolation valves in the shutdown cooling suction and vessel head spray lines are stroked at every, cold shutdown.
Testable check valves are only stroked at cold shutdown or refueling.
, 4.3.1.3 Local Leak Rate Test Local leak rate testing is performed on the inboard injection valves in the LPCI lines, on the shutdown cooling suction valves, on the feedwater check l valves, and on the MOVs in vessel head spray line. It is done every refueling and the test pressure is 48 psi.
r 4.3.1.4 ECCS Automatic Actuation Test This test is required once every refueling, and is performed at cold
, shutdown.
4.3.1.5 Valve Position Indication Surveillance This is performed at least once every two years, and the Quad Cities procedures state that it preferably be done during refueling. The MOVs and testable check valves are cycled while verifying that the control room indication accurately reflects valve position by observing the valve stem
4-25 movement and the local / remote position indicators. All PIVs are subject to this test except valves in RCIC system and the check valve in the vessel head spray line. , I.
4.3.2 LPCI Injection Lines The valve arrangement and test requirements in the the'LPCI lines are the same as those for Peach Bottom, except that the testable check valves are not leak tested, and that the auto actuation test is only done ac cold shutdown.
Therefore, the failure of the testable check valves may go undetected. Since Quad Cities has operated for more than ten years, and any failure in the past may have gone undetected, it has been assumed that the probability that the check valve is in a failed state is increased by a factor of ten. Also, if the check valve fails open, the time at which failure occurs is most likely to be before the year that is being considered. Therefore, if the MOV fails open any time in the year, overpressurization is assumed to result. Since inadvertent opening of the injection valve during an auto actuation testing is not considered as discussed above, a generic failure rate for MOVs transfer open is used. The Vermont Yankee event, in which the air operated check valve was leaking and the normally open injection valve fail to fully close when it was closed before the normally closed MOV was cycled, is judged to be credible for the LPCI lines at Quad Cities, because similar stroke test without pressure equalization is performed. This experience is used to estimate the frequency of overpressurization due to such scenario. Such overpressurizaticu is assumed to lead to small LOCA, because the isolation valves are only leaking. Figure 4.6 illustrates the small LOCA cvent tree for one of the LPCI lines at Quad Cities.
l The unavailability of the safe shutdown system is assumed to be the same as that t
for the HPCS of Grand Gulf.8 Due to the open crosstie between the LPCI loops, only the core spray system is considered available. The unavailability of the core spray system has been taken from the BNL reviews of the Shoreham PRA.
Table 4.14 summarizes the calculations for this line.
4.3.3 Core Spray Injection Lines
\ -
I j These lines differ from the Quad Cities LPCI lines in that the Cooper-type incident (i.e., foreign material under valve disc) is considered credible, in I
- - - , , - - - , - - . 7 - -y w.*, _y v
4-26 that the spargers are assumed to effectively prevent any sizable debris from working is way back to the check valves. Also, the low pressure system unavailabili y in the small LOCA event tree from Figure 4.6 is changed, the low pressure inj4ction function failure probability has been lowered to account for I the availability of one train of core spray and both trains of LPCI, whereas for the LPCI line failure event tree only the two core spray trains were available due to the LPCI crosstie. This lowered the failure probability of the low pressure injection function by a factor of 3.6 as is shown in Table 4.1A.
4.3.4 HPCI and RCIC The HPCI and RCIC injection lines at Quad Cities differ from those at Peach Bottom in that an additional check valve exists in the feedwater line and that the ECCS automatic actuation test is not done when the reactor is at power. The effect of the second feedwater check valve is a factor of ten reduction in the large LOCA frequency based on the assumption that large flow conditions will force the check valve closed and terminate the LOCA. Table 4.15 summarizes the calculations for these lines.
4.3.5 Feedwater Line Based on a meeting with plant personnel at Quad Cities the only safety related' equipment in the turbine building are electrical cables and some electrical buses and they are located far away from the feedwater heaters and at different elevations. Therefore, it has been assumed that no ECCS systems are affected by a large LOCA in any feedwater line, and the same quantitative analysis as that for Peach Bottom can be used.
4.3.6 RHR Suction and Vessel Head Spray The valve arrangements and test requirement for these lines are the same as those for Peach Bottom. The same quantitative results are therefore used.
.. . . . . . . . .. - ~ ..
4-27 4.4 References ;
- 1. H. S. h ta and R. W. Howard, "BWR Owner's Group Assessment of Emergency CoreCohingSystemPressurizationinBoilingWaterReactors,"DraftReport,2 June 30, 1986.
- 2. " Reactor Safety Study," WASH-1400, NUREG-75/014, U.S. Nuclear Regulatory Commission, 1975.
- 3. G. Apostolakis and T-L. Chu, " Time-Dependent Accident Sequences Including Human Actions," Nuclear Technology, Vol. 64, February 1984.
- 4. D. Ilberg and N. Hanan, "An Evaluation of Unisolated LOCA Outside the Drywell in the Shoreham Nuclear Power Station," Technical Report, A-3740, Brookhaven National Laboratory, June 18, 1985.
- 5. D. Ilberg, K. Shiu, N. Hanan, and E. Anavim, "A Review of the Shoreham Nuclear Power Station Probabilistic Risk Assessment," NUREG/CR-4050, May 1985.
- 6. A. D. Swain and H. E. Guttmann, " Handbook of Human Reliability Analysis With Emphasis on Nuclear Power Plant Applications," NUREG/CR-1278, August 1983.
l
[ 7. " Reference Plant Accident Sequence Likelihood Charactetization - Peach
- Bottom, Unit 2," Draf t Report, Vol. 3, NUREG/CR-4550, April 24,1986.
i
- 8. Steven W. Hatch, " Reactor Safety Study Hethodology Application Program Grand Gulf #1 BWR Power T; ant," NUREG/CR-1659/4-of-4, October 1981.
i l
E 4-28 4
, h-I 4
Overpressurization Maj or
(& Small LOCA) Pipe Rupture Isolation
- 1. OK 10-2 Unisolated
- 2. Snall LOCA 0.99x10-2 Unisolated 10-1, 10-3, 3.0x10-5 i
0.01
- 4. Large LOCA
, (Core Damage)
J
' Figure 4.1. Event tree for conditional probability of LOCAs resulting from an overpressurization.
i k
I I
4-29
.I- . . .
l ,
l i i 1 ----
q -
,s.% ...' ' g
.N.
- \
gN \ WASH-1400 Large LOCA *
-1 \ '- -
\'
10 k
\ N.\ Q MP
\
\ Cogniti*te Error
'g
'\ \ '
10~ - NUS ' ~ --d Control Room Team '.g ,'.,'\ . * ,Up'per Bound -
- y. ~~~~
~3
\ '.
. Nominal 10 Y"1"*
\ k O, WASH-1400 Large LOCA
\ \.,'. Control Room Team
\ '
t.
10" -
Lower Bound N '
'\,
.g .
10
-5 1 I 'x I 10 100 1000 Minutes Figure 4.2. Time curves for operator actions.
i
4-30 i
RCIC Depressurization LPCS Pump Q U X V'V" V"'
O.89 1 OK 10-3 2 OK 0.1 5.0x10-2 3 CM 4 OK 0.1 5 CM 6 OK 10-3 7 OK 0.1 5.0x10-2 8 CM
- 9 OK 0.1 10 CM f 0.11 11 0K f 10-3 12 OK i
1.0 0.1 13 CM i 8.4x10-4 4
14 CM l
i 4
Figure 4.3. Event tree for a small LOCA outside the containment (LPCI line at Peach Bottom).
4 4
i
--. ,__,-n -
,-.--,r------ , .-- ------------r
1 4-31 h-
.(
. . l Isolation Makeup OK ECCS OK CM 1.2x10-4 CM Figure 4.4 Event tree for feedwater heater rupture.
4-32
.l.
-l :
Depressuri- LPCI & Cond.
FW RCIC HPCS zation LPCS & HPCS Pump Q Ut U2 X V'V" V"'
O.89 1 OK 6.2x10-" 2 OK 0.1 5x10-" 3 CM 4 OK 0.1 5 OK 6 OK 6.2x10-4 7 OK 0.1 5x10-4 8 CM 9 OK 0.1 10 CM 0.11 11 OK 5x10-"
12 OK i 0.1
, 13 CM 1.0 14 OK 10-3 15 OK 2.2x10-2 0.1 16 CM 8.4x10-"
17 CM i
, NMP-2).
l -
i
. _ . _ - _ _ . _ - - _ - _ . _ . _ _ . - _ - _ . . . _ _ , _ _ _ _ - , _ _ ~ _ . _ _ _ _ _ - - . . _ _ _ _ . . . _ . _ _ _ _ - _ , . .. . _ . _ _ _ _ -
4-33 I.
~
Q U X V' V"'
i 0.89 1 OK 3.6x10-3 2 OK 5x10-2 3 CM 4 OK 0.1 5 CM 6 OK 3.6x10-3 7 OK O.1 l 5x10-2 8 CM 9 OK 0.1 10 CM 0.11 11 OK 3.6x10-3 12 OK 2.2x10-2 0.1 l ^ 13 CM l 8.'4x10-4
! 14 CM r
a Figure 4.6. Event tree for a small LOCA outside the containtsent (LPCI line at Quad Cities).
j 1
1 l
F 4-36 t
~.
Table 4.1 Some Data Used in the Quantification of the Frequency of Intersystem LOCAs
- 1. .
~
FailureEvenh Failure Data Sources -
- 1. MOV Rupture 1.20x10-3(/ry) See Appendix D
Closed 1.07x10-4(/ demand) Seabrook PRA f 4. MOV Inadvertently opened *
.x10-3(/ demand) Handbook of Human l Reliability Analysis
- 5. A0V Opened Due to Reversed Air Supply 1.47x10-3(/ry) See Appendix D
- 6. A0V Opened Due to Fareign Material 7.35x10-4(/ry) See Appendix D
- 7. A0V Opened Due to Rusted Linkage 7.35x10-4(/ry) See Appendix D l
- 8. A0V Opened Due to Misalignment of Gears 7.35x10-4(/ry) See Appendix D r
- 9. A0V Leak 2.94x10-3(/ry) See Appendix D
- 10. Check Valve Rupture 8.80x10-"(/ry) PSA Procedures Guide i
- 11. Check Valve Leak 2.94x10-3(/ry) Same as A0V Leak 12.Lamda Rupture Square (MOV) 2.06x10-6(/ry2) EX2 =(EX)2+ var.
13.Lamda Leak Square 2.20x10-8(/ry2) 2 EX =(EX) 2+ var.
l 14.Lamda Leak Square (A0V) 1.09x10-5(/ry2 ) 2 EX =(EX) 2+ var.
4
[ 15.Lamda Rust Square 2.13x10-6(/ry2) 2 EX =(EX) 2+ var.
r i
1 i
l
4-35 i
Table 4.1A Line Specific Failure Probabilities Used in the Small LOCA Event Trees I.
.f Q U X V'V" V"' CDP I Peach Bottom LPCI 0.11 1.0 5x10-2/8.4x10-" 10-3 0.1 4.64x10-3 LPCS 0.11 1.0 5x10-2/8.4x10-" 10-3 0.1 4.64x10-3 RHR Suction 0.11 1.0 l 5x10-2/8.4x10-" 10-3 0.1 4.64x10-3
- Head Spray 0.11 1.0 5x10-2/8.4x10-4 10-3 0.1 4.64x10-3 Quad Cities LPCI 0.11 2.2x10-2 5x10-2/0.4x10-" 3.6x10-3 0.1 5.36x10-3 i
LPCS 0.11 2.2x10-2 5x10-2/8.4x10-" 10-3 0.1 5.36x10-3 RHR Suction 0.11 2.2x10-2 5x10-2/8.4x10-4 3.6x10-3 0.1 5.36x10-3
, Head Spray 0.11 2.2x10-2 5x10-2/8.4x10-" 3.6x10-3 '0.1 5.36x10-3 i
Q Ut U2 X V'V" V"' CDP l
1 Nine Mile Point-2 LPCI 0.11 1.0 2.2x10-2 5x10-4/8.4x10-4 6.2x10-"
i 0.1 1.08x10-"
LPCS 0.11 1.0 2.2x10-2 5x10-4/8.4x10-4 /10-3 6.2x10-"/10-3 0.1 1.08x10-4 4 SDC Return 0.11 1.0 2.2x10-2 5x10-"/8.4x10-4 6.2x10-4/10-3 0.1 1.08x10-4 i HPCS 0.11 1.0 1.0 5x10-4/8.4x10-" 6.2x10-4 0.1 1.99x10-"
i Head Spray 0.11 1.0 2.2x10-2 5x10-"/8.4x10-" 6.2x10-"/10-3 0.1 1.08x10-4
} RHR Suction 0.11 1.0 2.2x10-2 5x10-4/8.4x10-" 6.2x10-"/10-3 0.1 1.08x10-4 l
Steam condensing 0.11 1.0 2.2x10-2 5x10-4/8.4x10-4 6.2x10-"/10-3 0.1 1.08x10-4 p.
i l
4 i
I i
l
4-36 Table 4.2 Summary of Results Plant f(OP) P(Rupture)
S2 A CDF .
Peach Bottom 9.01x10-3 1.00E-01 3.11E-05 1.05E-04 5.49x10-6 1.00E-03 3.12E-05 1.05E-06 1.98x10-7 3.00E-05 3.12E-05 3.16E-08 1.46x10-7 Nine Mile Point-2 9.93E-03 '1.00E-01 3.37E-05 3.23E-04 2.23E-04 1.00E-03 3.44E-05 3.23E-06 2.23E-06 3.00E-05 3.44E-05 9.68E-08 7.13E-08 Quad Cities 6.89x10-3 1.00E-01 4.15E-05 1.09E-04 9.59x10-6 1.00E-03 4.16E-05 1.09E-06 3.17x10-7 3.00E-05 4.16E-05 3.28E-08 2.26E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
i
4-37 Table 4.3 Summary of Results for Peach Bottom Line -
f(OP) P(Rupture) S2 A CDF ,
LPCI 1.52E-03 1.00E-01 1.52E-05 2.66E-06 2.73E-06 1.00E-03 1.52E-05 2.66E-08 9.73E-08 3.00E-05 1.52E-05 7.99E-10 7.14E-08 CS 1.52E-03 1.00E-01 1.51E-05 2.08E-06 2.15E-06 1.00E-03 1.52E-05 2.08E-08 9.11E-08 3.00E-05 1.52E-05 6.23E-10 7.10E-08 !
HPCI 2.97E-02 1.00E-01 0.00E+00 2.32x10-7 2.32x10-7 1.00E-03 0.00E+00 2.32x10-9 2.32x10-9 3.00E-05 0.00E+00 6.95x10-ll 6.95x10-Il RCIC 2.97E-02 1.00E-01 0.00E+00 2.32E-07 2.32x10-7 1.00E-03 0.00E+00 2.32E-09 2.32x10-9 3.00E-05 0.00E+00 6.95E-11 6.95x10-Il Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.92E-08 1.00E-03 7.71E-07 2.58E-10 3.83E-09 3.00E-05 7.71E-07 7.73E-12 3.59E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.72E-09
,' 1.00E-03 4.53E-08 1.51E-11 2.25E-10 3.00E-05 4.53E-08 4.54E-13 2.11E-10 N3tes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
. S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
'CDF = Core Damage Frequency (/ry).
i F
i
[
i
4-38 Table 4.4 List of PIVs Tested in Operational Hydrostatic Test at Peach Bottom n
Valve [ Acceptable Rate A0-14-13A Testable Check Valve, Core Spray A 360 cc/hr AO-14-13B Testable Check Valve, Core Spray B 360 cc/hr A0-10-46A Testable Check Valve, RHRA 720 cc/hr A0-10-46B Testable Check Valve, RHRB 720 cc/hr MO-10-25A Inboard Injection Valve, RHRA 720 cc/hr MO-10-253 Inboard Injection valve, RHRB 720 cc/hr M0-14-12A Inboard Injection Valve, Core Spray A 360 cc/hr MG-14-12B Inboard Injection valve, Core Spray B 360 cc/hr MO-10-18 Inboard Suction Valve, RHR Shutdown Cooling 600 cc/hr MO-10-17 Outboard Suction Valve, RHR Shutdown Cooling 600 cc/hr MO-23-19 Inboard Injection Valve, HPCI 420 cc/hr MO-13-21 Inboard Injection Valve, RCIC 180 cc/hr
4-39 Table 4.5 Summary of Calculations for LPCI of Peach Bottom
. Experience -
A0V MOV f(OP) P(Rupture) S2 A Browns Ferry-l' 1.47E-03 1.93 E-06 2.83E-09 0.00E+00 2.83E-11 0.00E+00 Hatch-2 Failure to 0.00E+00 2 43E-11 0.00E+00 (Reverse Air) Reclose 0.00E+00 2.83E-11 0.00E+00 6.00E-04 8.82E-07 1.00E-01 8.81E-09 8.82E-10 Ruptdre 1.00E-03 8.82E-09 8.82E-12 3.00E-05 8.82E-09 2.65E-13 3.00E-03 4.41E-06 1.00E-01 4.40E-08 4.41E-09 Inadvertent Opening 1.00E-03 4.41E-08 4.41E-11 3.00E-05 4.41E-08 1.32E-12
, 4.05E-04 5.95E-07 1.00E-01 5.95E-09 5.95E-10 Transfer Open 1.00E-03 5.95E-09 5.95E-12 3.00E-05 5.95E-09 1.79E-13 Browns Ferry Scenario 7.35E-04 1.00E-01 7.34E-06 7.35E-07 (Reverse Air, Inadvertent Opened) 1.00E-03 7.35E-06 7.35E-09 3.00E-05 7.35E-06 2.20E-10 Cooper 7.35E-04 1.93E-06 1.42E-09 0.00E+00 .1.42E-11 0.00E+00 (Foreign Material) Failure to 0.00E+00 1.42E-11 0.00E+00 Reclose 0.00E+00 1.42E-11 0.00E+00 6.00E-04 4.41E-07 1.00E-01 3.97E-09 4.41E-08 Rupture 1.00E-03 4.40E-09 4.41E-10 3.00E-05 4.41E-09 1.32E-11 f 3.00E-03 2.20E-06 1.00E-01 1.98E-08 2.20E-07 Inadvertent Opening 1.00E-03 2.20E-08 2.20E-09 3.00E-05 2.20E-08 6.61E-11 4.05E-04 2.98E-07 1.00E-01 2.68E-09 2.98E-08 Transfer Open 1.00E-03 2.97E-09 2.98E-10 3.00E-05 2.98E-09 8.93E-12
, Pilgrim-1 7.35E-04 1.93E-06 1.42E-09 0.00E+00 1.42E-11 0.00E+00 Sept. 29, 1983 Failure to Reclose 0.00E+00 1.42E-11 0.00E+00 (Rusted Linkage) 0.00E+00 1.42E-11 0.00E+00 6.00E-04 4.41E-07 1.00E-01 4.40E-09 4.41E-10 Rupture 1.00E-03 4.41E-09 4.41E-12 3.00E-05 4.41E-09 1.32E-13 3.00E-03 2.20E-06 1.00E-01 2.20E-08 2.20E-09 Inadvertent Opening 1.00E-03 2.20E-08 2.20E-11 3.00E-05 2.20E-08 6.61E-13 4.05E-04 2.98E-07 1.00E-01 2.97E-09 2.98E-10 Transfer Open 1.00E-03 2.98E-09 2.98E-12 3.00E-05 2.98E-09 8.93E-14 4
- - - - - + > - - - . , , - . - - - - , , - - - - - , , , .a -,-.-,n. - - - - , - - - - - - . - - - - - - - - - . . - - - , - - - _ _
~
4-40 Table 4.5 (Continued)
Experience A0V MOV f(OP) P(Rupture) S2 A LaSalle-1 h 7.35E-04 1.93E-06 1.42E-09 0.00E+00 1.42E-11 0.00E+00 Sept. 14, 1983 Failure to Reclose 0.00E+00 1.42E-11 0.00E+00 (Misalignment of Gears) 0.00E+00 1.42E-11 0.00E+00 6.00E-04 4.41E-07 1.00E-01 3.97E-09 4.41E-08 Rupture 1.00E-03 4.40E-09 4.41E-10 3.00E-05 4.41E-09 1.32E-11 3.00E-03 2.20E-06 1.00E-01 1.98E-08 2.20E-07 Inadvertent Opening 1.00E-03 2.20E-08 2.20E-09 3.00E-05 2.20E-08 6.61E-11 4.05E-04 2.98E-07 1.00E-01 2.68E-09 2.98E-08 Transfer Open 1.00E-03 2.97E-09 2.98E-10 3.00E-05 2.98E-09 8.93E-12 Four Remaining 2.94E-03 1.93E-06 5.66E-09 0.00E+00 5.66E-11 0.00E+00 Incidents Failure to Reclose 0.00E+00 5.66E-11 0.00E+00 (Leakage) 0.00E+00 5.66E-11 0.00E+00 6.00E-04 1.76E-06 0.00E+00 1.76E-08 0.00E+00 Rupture 0.00E+00 1.76E-08 0.00E+00 0.00E+00 1.76E-08 0.00E+00 3.00E-03 8.82E-06 0.00E+00 8.82E-08 0.00E+00 Inadvertent Opening 0.00E+00 8.82E-08 0.00E+00 0.00E+00 8.82E-08 0.00E+00 4.05E-04 1.19E-06 0.00E+00 1.19E-08 0.00E+00 Transfer Open 0.00E+00 1.19E-08 0.00E+00 0.00E+00 1.19E-08 0.00E+00 Nstas: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
A0V = Failure Rate of Air Operated Check Valve (/ry).
MOV = Probability of MOV Failure.
4
F- p4 4-41 Table 4.6 Summary of Calculations for RCIC and HPCI of Peach Bottom Experience '
A0V MOV f(OP) P(Rupture) S2 . A Browns Ferry-1 1.47E-02 1.20E-03 1.76E-05 1.00E-01 0.00E+00 1.76E-09 Hatch-2 Rupture 1.00E-03 0.00E+00 1.76E-11 (Reversed Air) 3.00E-05 0.00E+00 5.29E-13 3.00E-03 4.41E-05 1.00E-01 0.00E+00 4.41E-09 Inadvertent Opening 1.00E-03 0.00E+00 4.41E-11 3.00E-05 0.00E+00 1.32E-12 8.10E-04 1.19E-05 1.00E-01 0.00E+00 1.19E-09 Transfer Open 1.00E-03 0.00E+00 1.19E-11 3.00E-05 0.00E+00 3.57E-13 Browns Ferry Scenario 7.35x10-4 1.00E-01 0.00E+00 7.35x10-8 (Reverse Air, Inadvertent Opened) 1.00E-03 0.00E+00 7.35x10-10 3.00E-05 0.00E+00 2.20x10-Il Cooper 7.35E-03 1.20E-03 8.82E-06 1.00E-01 0.00E+00 8.82E-09 (Foreign Material) 1.00E-03 0.00E+00 8.82E-11 3.00E-05 0.00E+00 2.65E-12 3.00E-03 2.20E-05 1.00E-01 0.00E+00 2.20E-08 1.00E-03 0.00E+00 2.20E-10 3.00E-05 0.00E+00 6.61E-12 8.10E-04 5.95E-06 1.00E-01 0.00E+00 5.95E-09 1.00E-03 0.00E+00 5.95E-11 3.00E-05 0.00E+00 1.79E-12.
Pilgrim-1 7.35E-03 1.20E-03 8.82E-06 1.00E-01 0.00E+00 8.82E-10 Sept. 29, 1983 Rupture 1.00E-03 0.00E+00 8.82E-12 (Rusted Linkage) 3.00E-05 0.00E+00 2.65E-13 3.00E-03 2.20E-05 1.00E-01 0.00E+00 2.20E-09 Inadvertent Opening 1.00E-03 0.00E+00 2.20E-11 3.00E-05 0.00E+00 6.61E-13 8.10E-04 5.95E-06 1.00E-01 0.00E+00 5.95E-10 Transfer Open 1.00E-03 0.00E+00 5.95E-12
, , 3.00E-05 0.00E+00 1.79E-13 Pilgrim Scenario 7.35E-04 1.00E-01 0.00E+00 7.35E-08 (Rusted Linkage, HE in Testing) 1.00E-03 0.00E+00 7.35E-10 i
3.00E-05 0.00E+00 2.20E-11 LaSalle-1 7.35E-03 1.20E-03 8.82E-06 1.00E-01 0.00E+00 8.82E-09 Sept. 14, 1983 Rupture 1.00E-03 0.00E+00 8.82E-11 (Misalignment of Gears) 3.00E-05 0.00E+00 2.65E-12 3.00E-03 2.20E-05 1.00E-01 0.00E+00 2.20E-08 Inadvertent Opening 1.00E-03 0.00E+00 2.20E-10 3.00E-05 0.00E+00 6.61E-12 1 -
8.10E-04 5.95E-06 1.00E-01 0.00E+00 5.95E-09 Transfer Open 1.00E-03 0.00E+00 5.95E-11 3.00E-05 0.00E+00 1.79E-12 CSIs Notes of Table 4.5.
b L
4-42 Table 4.7 Summary of Results for Nine Mile Point-2 t
Line -I f(OP) P(Rupture) S2 A CDF .
LPCI 1.33E-05 1.00E-01 7.85E-06 2.24E-07 2.25E-07 1.00E-03 7.99E-06 2.24E-09 3.37x10-9 1
3.00E-05 7.99E-06 6.71E-11 1.2x10-9 LPCS 3.69E-06 "1.00E-01 2.22E-06 7.38E-10 1.05x10-8 1.00E-03 2.22E-06 7.38E-12 3.21x10-10 3.00E-05 2.22E-06 2.22E-13 3.14x10-10
~
SDC Return 8.86E-06 1.00E-01 5.24E-06 1.49E-07 1.50E-07 1.00E-03 5.33E-06 1.49E-09 2.07E-09 3.00E-05 5.33E-06 4.47E-11 6.20E-10 HPCS 2.65E-07 1.00E-01 2.65E-07 3.25E-13 5.31E-11 1.00E-03 2.65E-07 3.25E-15 5.28E-11 3.00E-05 2.65E-07 9.75E-17 5.28E-11 Vessel Head Spray 4.35E-06 1.00E-01 5.05E-08 5. 34E-11 2. 74x10- 10 1.00E-03 5.05E-08 5.34E-13 2.21x10-10 3.00E-05 5.05E-08 1.60E-14 2.20x10- 10 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.58E-08 1.00E-03 7.71E-07 2.58E-10 3.41E-10 3.00E-05 7.71E-07 7.73E-12 9.10E-11 Steam Condensing 8.90E-03 1.00E-01 1.73x10-5 2.22E-04 2.22E-04 1.00E-03 1.78x10-5 2.22E-06 2.23E-06 3.00E-05 1.78x10-5 6.67E-08 6.86E-08 J
Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
4-43 Table 4.8 PIVs Tested in PIV Leak Rate Test at Nine Mile Point t
b Success Criteria Valve .f Description Gal / Min F041(16)* Testable Check Valve, LPCI 5.0 F042(24) Injection Valve, LPCI 5.0 F009(112) Shutdown Cooling S6ction Valve 5.0 F008(113) Shutdown Cooling Suction valve 5.0 F050(39) Testable Check Valve, Shutdown Cooling Return 5.0 F053(40) Injection Valve, Shutdown Cooling Return 5.0 F052(22) Steam Supply to RHR HX 4.0 F218(80) RHR Steam Line Bypass 0.5 F051(21) RHR HX Press. Cont. 4.0 F087(23) Steam Supply to RHR HX 4.0 F006(101) Testable Check Valve, LPCS 5.0 F005(104) Injection Valve, LPCS 5.0 F005(108) Testable Check Valve, HPCS 5.0 F004(107) Injection Valve, HPCS 5.0 F066(157) Testable Check Valve, RCIC 1.0 F065(156) Testable Check Valve, RCIC 1.0
- Number in parenthesis is the valve number used by Stone & Webster.
i n . -
4-44 Table 4.9
. Summary Calculations for LPCI of Nine Mile Point-2 Exp3rience -
A0V MOV f(OP) P(Rupture) S2 A.
Cosper 7.35E-04 6.00E-04 4.41E-07 1.00E-01 3.97E-07 4.41E-08 (Fcreign Material) Rupture 1.00E-03 4.40E-07 4.41E-10 3.00E-05 4.41E-07 1.32E-11 4.05E-04 2.98E-07 1.00E-01 2.68E-09 2.98E-08 Trans'fer Open 1.00E-03 2.97E-09 2.98E-10 3.00E-05 2.98E-09 8.93E-12 Pilgrim-1 7.35E-04 6.00E-04 4.41E-07 1.00E-01 4.40E-07 4.41E-10 Sept. 29, 1983 Rupture 1.00E-03 4.41E-07 4.41E-12 3.00E-05 4.41E-07 1.32E-13 4.05E-04 2.98E-07 1.00E-01 2.97E-09 2.98E-10 Transfer Open 1.00E-03 2.98E-09 2.98E-12 3.00E-05 2.98E-09 8.93E-14 Fcur Remaining 2.94E-03 6.00E-04 1.76E-06 0.00E+00 1.76E-06 0.00E+00 Incidents Rupture 0.00E+00 1.76E-06 0.00E+00 (Lesk) 0.00E+00 1.76E-06 0.00E+00 4.05E-04 1.19E-06 0.00E+00 1.19E-08 0.00E+00 Transfer Open 0.00E+00 1.19E-08 0.00E+00 0.00E+00 1.19E-08 0.00E+00 Nst s: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 - Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
A0V = Failure Rate of Air Operated Check Valve (/ry).
MOV = Probability of MOV Failure.
l l
4-45 Table 4.10 Summary Calculations for HPCS of Nine Mile Point-2 5
Experience ~ A0V MOV Check f(OP) P(Rupture) S2 A .
Pilgrim-1 7.35E-04 2.14E-04 5.88E-02 9.25E-09 0.00E+00 9.25E-09 0.00E+00 Sept. 29, 1983 Failura Leak 0.00E+00 9.25E-Q9 0.00E+00 (Rutted Linkage) to Reclose 0.00E+00 9.25E-09 0.00E+00 4.40E-04 6.92E-11 0.00E+00 6.92~-11 0.00E+00 Rupture 0.00E+00 6.92E-11 0.00E+00 0.00E+00 6.92E-11 0.00E+00 6.00E-04 5.88E-02 2.5Vd-08 0.00E+00 2.59E-08 0.00E+00 Rupture Leak 1 0.00E+00 2.59E-08 0.00E+00
=
0.00E+00 2.59E-08 0.00E+00 4.40E-04 1.94E-10 1.00E-01 1.94E-10 1.94E-13 Rupture 1. 00E-03 1.94E-10 1. 94E-15 3.00E-05 1.94E-10 5.82E-17 4.05E-04 5.88E-02 1.75E-08 0.00E+00 1.75E-08 0.00E+00 Transfer Leak 0.00E+00 1.75E-08 0.00E+00 Open 0.00E+00 1.75E-08 0.00E+00 4.40E-04 1.31E-10 1.00E-01 1.31E-10 1.31E-13 Rupture 1.00E-03 1.31E-10 1.31E-15 3.00E-05 1.31E-10 3.93E-17 Fcur Remaining 2.94E-03 2.14E-04 5.88E-02 3.70E-08 0.00E+00 3.70E-08 0.00E+C0 Incidents Failure Leak O.00E+00 3.70E-08 0.00E+00 to Reclose 0.00E+00 3.70E-08 0.00E+00 4.40E-04 2.77E-10 0.00E+00 2.77E-10 0.0C;r00 Rupture 0.00E+00 2.77E-10 0.00E+00 0.00E+00 2.77E-10 0.00E+00 6.00E-04 5.88E-02 1.04E-07 0.00E+00 1.04E-07 0.00E+00 Rupture Leak 0.00E+00 1.04E-07 0.00E+00 0.00E+00 1.04E-07 0.00E+00 4.40E-04 7.76E-10 0.00E+00 7.76E-10 0.00E+00 Rupture 0.00E+00 7.76E-10 0.00E+00 0.00E+00 7.76E-10 0.00E+00 4.05E-04 5.88E-02 7.00E-08 0.00E+00 7.00E-08 0.00E+00 Transfer Leak O.00E+00 7.00E-08 0.00E+00 Open 0.00E+00 7.00E-08 0.00E+00 4.40E-04 5.24E-10 0.00E+00 5.24E-10 0.00E+00
. Rupture 0.00E+00 5.24E-10 0.00E+00 0.00E+00 5.24E-10 0.00E+00 Notcs: f(OP) = Frequency of Overpressurization (/ry).
F(Rupture) - Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A - Frequency of Large LOCA (/ry).
A0V = Failure Rate of Air Operated Check Valve (/ry).
MOV = Probability of MOV Failure.
4-46 Table 4.11 Summary of, Calculations for Vessel Head Spray of Nine Mile Point-2 a
Experience: '
A0V1 A0VN A0Vs MOV P(Rupture) f(OP) S2 A !
I Leak + Leak 5.45E-06 2.14E-04 1.63E-09 0.00E+00 1.63E-09 0.00E+00 ;
Leak + Rusted Linkage 1.08E-06 Failure to 0.00E+00 1.63E-09 0.00E+00 ,
Rusted Linkage + Leak 1.08E-06 Reclose 0.00E+00 1.63E-09 0.00E+00 6.00E-04 4.57E-09 0.00E+00 4.57E-09 0.00E+00 ,,
Rupture 0.00E+00 4.57E-09 0.00E+00 Total Leak 7.61E-06 0.00E+00 4.57E-09 0.00E+00 5.00E-01 3.80E-06 0.00E+00 3.80E-08 0.00E+00 Opened in Test 0.00E+00 3.80E-08 0.00E+00
' 0.00E+00 3.80E-08 0.00E+00 4.05E-04 3.08E-09 0.00E+00 3.08E-11 0.00E+00 Transfer Open 0.00E+00 3.08E-11 0.00E+00 0.00E+00 3.08E-11 0.00E+00 Rusted Linkage (both) 1.06E-06 2.14E-04 2.28E-10 0.00E+00 2.28E-10 0.00E+00 Failure to 0.00E+00 2.28E-10 0.00E+00 Reclose 0.00E+00 2.28E-10 0.00E+00 6.00E-04 6.39E-10 1.00E-01 6.39E-10 6.39E-14 Rupture 1.00E-03 6.39E-10 6.39E-16 3.00E-05 6.39E-10 1.92E-17 5.00E-01 5.32E-07 1.00E-01 5.32E-09 5.33E-11 Opened in Test 1.00E-03 5.32E-09 5.33E-13 3.00E-05 5.32E-09 1.60E-14 4.05E-04 4.31E-10 1.00E-01 4.31E-12 4.31E-14 Transfer Open 1.00E-03 4.31E-12 4.31E-16 3.00E-05 4.31E-12 1.29E-17 Notes: f(OP) = Frequency of Overpressurization (/ry).
, P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
A0V = Failure Rate of Air Operated Check Valve (/ry).
! HOV = Probability of MOV Failure.
t t
l
4-47 Table 4.12 Summary Calculations for Steam Condensing Lines of Nine Mile Point-2 Pair MOV1 MOV2 f(OP) P(Rupture) S2 A . .
F052&F087 4.00E+00 2.28E-08 9.13E-08 1.00E-01 1.74x10-10 4.57E-09 Cycling Rupture 1.00E-03 1.83x10-10 4.57E-Il per ry .
3.00E-05 1. 83x10- 10 1.37E-12 2.02E-04 8.10E-04 1.00E-01 1.54x10-6 4.05E-05 Trans fei- 1.00E-03 1.62x10-8 4.05E-07 Open 3.00E-05 1.62x10 1.21E-08 1.20E-03 6.00E-04 1.03E-06 1.00E-01 1.96x10-9 5.15E-08 Rupture Rupture 1.00E-03 2.06x10-9 5.15E- 10
- 3.00E-05 2.06x10-9 1.55E-Il 5.00E-01 6.00E-04 1.00E-01 1.14x10-8 3.00E-05 Interlock 1.00E-03 1.20x10-' 3.00E-07 Calibration 3.00E-05 1. 20x10- 6 9.00E-09 8.10E-04 9.72E-07 1.00E-01 1.85x10-9 4.86E-08 Transfer 1.00E-03 1.94x10-9 4.86E-10 l Open 3.00E-05 1.94x10-9 1.46E-Il F218&F087 4.00E+00 2.28E-08 9.13E-08 1.00E-01 1.83x10-10 Cycling Rupture 1.00E-03 1.83x10- 10 0.00E+00 0.00E+00 per ry 3.00E-05 1.83x10-10 0.00E+00 2.02E-04 8.10E-04 1.00E-01 1.62x10-' O.00E+00 Transfer 1.00E-03 1.62x10-6 0.00E+00 i Open 3.00E-05 1.62x10-6 0.00E+00 1.20E-03 6.00E-04 1.03E-06 1.00E-01 2.06x10-9 0.00E+00 Rupture Rupture 1.00E-03 2.06x10-9 0.00E+00 3.00E-05 2.06x10-9 0.00E+00 5.00E-01 6'.00E-04 1.00E-01 1.2x10-8 0.00E+00 Interlock 1.00E-03 1.2x10-6 0.00E+00 Calibration 3.00E-05 1. 2x10- 6 0.00E+00 8.10E-04 9.72E-07 1.00E-01 1.94x10-9 0.00E+00 Transfer 1.00E-03 1.94x10-9 0.00E+00 Open , 3.00E-05 1.94x10-'8 0.00E+00 F052&F051 4.00E+00 2.28E-08 9.13E-08 1.0CE-01 1.74x10-10 4.57E-09 t Cycling Rupture 1.00E-03 1.83x10- 10 4.57E-11 per ry 3.00E-05 1.83x10- 10 1.37E-12 2.02E-04 8.10E-04 1.00E-01 1.54x10-6 4.05E-05 Transfer 1.00E-03 1.62x10-6 4.05E-07 Open 3.00E-05 1.62x10- 6 1.21E-08 1.20E-03 6.00E-04 1.03E-06 1.00E-01 1.96x10-9 5.15E-08 Rupture Rupture 1.00E-03 2.06x10-9 5.15E-10 3.00E-05 2.06x10-9 1.55E-Il 8.10E-04 9.72E-07 1.00E-01 1.85x10-9 4.86E-08 Transfer 1.00E-03 1.94x10-9 4.86E-10 Open 3.00E-05 1.94x10-9 1.46E-11 5
- _ - - . . . - - _ - - ,-- ...--. ..v-_ , , - , - - _ - , - - - . , - , - - - , - -- -- -
4-48 Table 4.12 (Continued) i Pair }, MOV1 MOV2 f(OP) P(Rupture) S2 A F218&F051 l4.00E+00 2.28E-08 9.13E-08 1.00E-01 1.83x10-10 0.00E+00 I Cycling Rupture 1.00E-03 1.83x10- 10 0.00E+00 per ry 3.00E-05 1.83x10- 10 0.00E4f1 2.02E-04 8.10E-04 1.00E-01 1. 62x10-6 0.00E+w4 Transfer '
1.00E-03 1.62x10-6 0.00E+00 !
Open 3.00E-05 1.62x 10- 6 0.00E+00 1.20E-03 6.00E-04 1.03E-06 1.00E-01 2.06x10-9 0.00E+00 Rupture Rupture 1.00E-03 2.06x10-9 0.00E+00 3.00E-05 2.06x10-9 0.00E+00 8.10E-04 9.72E-07 1.00E-01 1.94x10-9 0.00E+00 Transfer 1.00E-03 1.94x10-9 0.00E+00 Open 3.00E-05 1.94x10-9 0.00E+00 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
MOV = Probability of MOV Failure.
i 4
4-49 Table 4.13 Summary of Results for Quad Cities Line f(OP) P(Rupture) S2 A CDF .
LPCI 2.07E-03 1.00E-01 2.07E-05 6.00E-06 -5.11E-06 1.00E-03 2.07E-05 6.00E-08 1.71E-07 3.00E-05 2.07E-05 1.80E-09 1.13E-07 CS 2.01E-03 l'.00E-01 2.00E-05' 3.04E-06 3.15E-06 1.00E-03 2.01E-05 3.04E-08 1.38E-07 3.00E-05 2.01E-05 9.13E-10 1.09E-07 HPCI 7.52E-03 1.00E-01 0.00E+00 9.42x10-8 9.42x10- 8 1.00E-03 0.00E+00 9.42x10-10 9.42x10-10 3.00E-05 0.00E+00 2.82x10-Il 2.82x10-Il RCIC 7.52E-03 1.00E-01 0.00E+00 9.42x10-8 9.42x10-8 1.00E-03 0.00E+00 9.42x10- 10 9.42x10- 10 3.00E-05 0.00E+00 2.82x10-Il 2.82x10-Il Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.97E-08 1.00E-03 7.71E-07 2.58E-10 4.39E-09 3.00E-05 7.71E-07 7.73E-12 4.14E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.75E-09 1.00E-03 4.53E-08 1.51E-11 2.58E-10 3.00E-05 4.53E-08 4.54E-13 2.43E-10 Notes: 'f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
i
4-50 Table 4.14
, Summary Calculations for LPCI of Quad Cities s-Experience- A0V MOV f(OP) P(Rupture) S2 A .
Browns Ferry-1 1.47E-02 2.57E-03 3.77E-05 0.00E+00 3.77E-07 0.00E+00 Hatch-2 Failure to 0.00E+00 3.77E-07 0.00E+00 (Reverse Air) Reclose 0.00E+00 3.77E-07 0.00E+00 1.20E-03 1.76E-05 1.00E-01 1.76E-07 1.76E-08 Rapture 1.00E-03 1.76E-07 1.76E-10 3.00E-05 1.76E-07 5.29E-12 8.10E-04 1.19E-05 1.00E-01 1.19E-07 1.19E-08 Transfer Open 1.00E-03 1.19E-07 1.19E-10 3.00E-05 1.19E-07 3.57E-12 Cooper 7.35E-03 2.57E-03 1.89E-05 0.00E+00 1.89E-07 0.00E+00 (Foreign Material) Failure to 0.00E+00 1.89E-07 0.00E+00 Reclose 0.00E+00 1.69E-07 0.00E+00 1.20E-03 8.82E-06 1.00E-01 7.94E-08 8.82E-07 Rupture 1.00E-03 8.81E-08 8.82E-09 3.00E-05 8.82E-08 2.65E-10 8.10E-04 5.95E-06 1.00E-01 5.36E-08 5.95E-07 Transfer Open 1.00E-03 5.95E-08 5.95E-09 3.00E-05 5.95E-08 1.79E-10 Pilgrim-1 7.35E-03 2.57E-03 1.89E-05 0.00E+00 1.89E-07 0.00E+00 Sept. 29, 1983 Failure to 0.00E+00 1.89E-07 0.00E+00 (Rusted Linkage) Reclose 0.00E+00 1.89E-07 0.00E+00 1.20E-03 8.82E-06 1.00E-01 8.81E-08 8.82E-09 Rupture 1.00E-03 8.82E-08 8.82E-Il 3.00E-05 8.82E-08 2.65E-12 8.10E-04 5.95E-06 1.00E-01 5.95E-08 5.95E-09 Transfer Open 1.00E-03 5.95E-08 5.95E-Il 3.00E-05 5.95E-08 1.79E-12 LaSalle-1 7.35E-03 2.57E-03 1.89E-05 0.00E+00 1.89E-07 0.00E+00 Sept. 14, 1983 Failure to 0.00E+00 1.89E-07 0.00E+00 (Misalignment of Gears) Reclose 0.00E+00 1.89E-07 0.00E+00 1.20E-03 8.82E-06 1.00E-01 7.94E-08 8.82E-07 Rupture 1.00E-03 8.81E-08 8.82E-09 3.00E-05 8.82E-08 2.65E-10 8.10E-04 5.95E-06 1.00E-01 5.36E-08 5.95E-07 Transfer Open 1.00E-03 5.95E-08 5.95E-09 3.00E-05 5.95E-08 1.79E-10
4-51 Table 4.14 (Continued)
Experience;I. A0V MOV f(OP) P(Rupture) S2 A 1
FourRemaindbg 2.94E-02 2.57E-03 7.55E-05 0.00E+00 7.55E-07 0.00E+00 Incidents Failure to 0.00E+00 7.55E-07 0.00E+00 (Leak) Reclose 0.00E+00 7.55E-07 0.00E+90 1.20E-03 3.53E-05 0.00E+00 3.53E-07 0.00E+00 Rupture 0.00E+00 3.53E-07 0.00E+00 0.00E+00 3.53E-07 0.00E+00 8.10E-04 2.38E-05 0.00E+00 2.38E-07 0.00E+00 Transfer Open 0.00E+00 2.38E-07 0.00E+00 0.00E+00 2.38E-07 0.00E+00 Vermont Yankee 7.35E-04 0.00E+00 7.35E-06 0.00E+00 Scenario 0.00E+00 7.35E-06 0.00E+00 (Leak, Fall to Fully Closci 0.00E+00 7.35E-06 0.00E+00 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
A0V = Failure Rate of Air Operated Check Valve (/ry).
MOV = Probability of MOV Failure.
4 4
L 4
-- -~ n m ----n-- m-e o -m-
, - - . .- . . ~ ,- .
l t
4-52 Table 4.15 Summary of Calculations for RCIC and HPCI of Quad Cities s
Experience' A0V MOV f(OP) P(Rupture) S2 A .
i < >
Browns Ferry-1 1.47E-02 1.20E-03 1.76E-05 1.00E-01 0.00E+00 1.76E-09 ,
Hatch-2 Rupture 1.00E-03 0.00E+00 1.76E-11 (Reverse Air) 3.00E-05 0.00E+00 5.29E-13
[
?
8.10.E-04 1.19E-05 1.00E-01 0.00E+00 1.19E-09 '
Transfer Open 1.00E-03 0.00E+00 1.19E-11 ,
3.00E-05 0.00E+00 3.57E-13 '
cooper 7.35E-03 1.20E-03 8.82E-06 1.00E-01 0.00E+00 8.82E-10 (Foreign Material) Rupture 1.00E-03 0.00E+00 8.82E-12 3.00E-05 0.00E+00 2.65E-13 8.10E-04 5.95E-06 1.00E-01 0.00E+00 5.95E-10 Transfer Open 1.00E-03 0.00E+00 5.95E-12 3.00E-05 0.00E+00 1.79E-13 Pilgrim-1 7.35E-03 1.20E-03 8.82E-06 1.00E-01 0.00E+00 8.82E-10 Sept. 29, 1983 Rupture 1.00E-03 0.00E+00 8.82E-12
,. (Rusted Linkage) 3.00E-05 0.00E+00 2.65E-13 8.10E-04 5.95E-06 1.00E-01 0.00E+00.5.95E-10
. Transfer Open 1.00E-03 0.00E+00 5.95E-12 3.00E-05 0.00E+00 1.79E-13 Pilgrim Scenario 7.35E-04 1.00E-01 0.00E+00 7.35E-08 (Rusted Linkage, Failure to Fully Close) 1.00E-03 0.00E+00 7.35E-10 3.00E-05 0.00E+00 2.20E-11 LaSalle-1 7.35E-03 1.20E-O3' 8.82E-06 1.00E-01 0.00E+00 8.82E-09 Sept. 14, 1983 Rupture 1.00E-03 0.00E+00 8.82E-11
- (Misalignment of Gears) 3.00E-05 0.00E+00 2.65E-12 8.10E-04 5.95E-06 1.00E-01 0.00E+00 5.95E-09 Transfer Open 1.00E-03 0.00E+00 5.95E-11 d
3.00E-05 0.00E+00 1.79E-12 Notes: f(OP) = Frequency of Overpressurization (/ry).
l' P(Rupture) = Probability of Major Pipe Rupture.
j S2 = Frequency of Unisolated Small LOCA (/ry).
l A = Frequency of Large LOCA (/ry).
( A0V = Failure Rate of Air Operated Check Valve (/ry).
! MOV = Probability of MOV Failure.
i I
I i l
l l
1
5-1
- 5. CORRECTIVE ACTIONS AND THEIR EFFECT ON CORE DAMAGE FREQUENCY Inthidsection,correctiveactionsforeachofthethreeplantsare discussed. h1ut effect of the corrective actions on the frequency of -
overpressurization, the frequencies of LOCAs, and the frequency of core damage is provided. i k
5.1 Corrective Actions for Peach Bottom Three corrective actions are considered for Peach Bottom. They are described in this section. Table 5.1 summarizes the base case results listed in Tables 4.2 and 4.3. Tables 5.2.to 5.4 summarize the quantitative results if the corrective actions are separately implemented. Table 5.5 shows the results if all three corrective actions are implemented. They can be compared with the results for the base case listed in Table 5.1.
5.1.1 Leak Test of Air Operated Check Valves After Maintenance Some experienced failures of air operated check valves were caused by human errors during maintenance of the valves, e.g., events at Browns Ferry 1, Hatch 2, and LaSalle 1. These human errors can be detected and corrected, if a leak test is performed after maintenance. The test could be a LLRT or a PlV leak test. Table 5.2.shows the line by line results if this corrective action is implemented.
5.1.2 Perform Logic System Functional Test of ECCS Systems at Shutdown The Browns Ferry incident occurred when a human error was committed in a logic system functional test. If such a test is not performed when the reactor is at power, the Browns Ferry type of incident no longer applies to Peach Bottom. Table 5.3 shows the line by line results if the MOV failure mode of inadvertent opening is removed from the base case calculations.
5-2 5.1.3 Leak Test of Air Operated Check Valves in the HPCI and RCIC Injection Lines at Every Refueling
- l-Thesehalvesarecurrentlynotleaktested.
In the base case analysis in 4
Section 4, it was assumed that the check valve failure will not be detected, and this increased the frequency of check valve failure by a factor of ten and the
, exposure time of the MOV by a fsetor of two. Table 5.4 shows the results if these factors are removed.
5.2 Corrective Actions for Nine Mile Point 2 4
l Two corrective actions are considered for Nine Mile Point 2. They are described in this section. Table 5.6 summarizes the base case results for Nine 3
Mile Point lisced in Tables 4.2 and 4.7. Tables 5.7 and 5.8 summarize the results given that the corrective actions are separately impicmented. Table 5.9 shows the results if both corrective actions are implemented. Tables 5.7 to 5.9 can be compared with Table 5.6 to determine the benefits of the corrective actions.
l 5.2.1 Do Not Cycle Valves F052 and F218 at Power t
Based on the analysis of Section 4, the dominant contributor to the core damage frequency due to an interfacing LOCA at Nine Mile Point 2 is that valves F052A(B) and F218A(B) are cycled open and the other MOVs in the lines fail open. Cycling of these valves at power makes these valves ineffective pressure l barriers. If these valves are cycled only when the reactor is shutdown, the dominant core damage scenario is removed. Table 5.7 summarizes the line by line results if they are not cycled at power.
5.2.2 Do Not Cycle F087 at Power
- Valyes F087A and F087B are cycled at power when the interlocks for them are calibrated. For the same reason as was discussed in Section 5.2.1, cycling these valves at power increases the frequency of overpressurization and the frequency of core damage. Table 5.8 shows the line by line results if these valves are not cycled at power.
i L
5-3 5.3 Corrective Actions for Quad Cities TwocokrectiveactionsareconsideredforQuadCities. They are described inthissecfion. Table 5.10 summarizes the base case results listed in Table 4.2 and 4.13. Tables 5.11 and 5.12 summarize the quantitative results if the corrective actions are separately implemented. Table 5.13 summarizes the '
results if both corrective actions are implemented.
5.3.1 Leak Test Air Operated Check Valves The air operated check valves at Quad Cities are currently not leak tested ,
in any way. As was analyzed in Section 4, this caused a factor of ten increase in the probability of check valve failure and a factor of two increase in the exposure time of the MOV. Table 5.11 shows the line by line results for the corrective action of leak testing the air operated check valves every refueling.
5.3.2 Leak Test Air Operatet', Check Valves Af ter Maintenance This corrective action is identical to that for Peach Bottom discussed in Section 5.1.1. Table 5.12 shows the results for this corrective action.
I E
i
-- w - w -
z, - -
5-4 Table 5.1 Summary of Results for Peach Bottom - Base Case Line : ' f(OP) P(Rupture) S2 A CDF ,
LPCI 1.52E-03 1.00E-01 1.52E-05 2.66E-06 2.73E-06 1.00E-03 1.52E-05 2.66E-08 9.73E-08 3.00E-05 1.52E-05 7.99E-10 7.14E-08 CS 1.52E-03 1.00E-01 1.51E-05 2.08E-06 2.15E-06 1.00E-03 1.52E-05 2.08E-08 9.11E-08' 3.00E-05 1.52E-05 6.23E-10 7.10E-08 HPCI 2.48E-03 1.00E-01 0.00E+00 2.32E-07 2.32E-07 1.00E-03 0.00E+00 2.32E-09 2.32E-09 3.00E-05 0.00E+00 6.95E-11 6.95E-11 RCIC 2.48E-03 1.00E-01 0.00E+00 2.32E-07 2.32E-07 1.00E-03 0.00E+00 2.32E-09 2.32E-09 3.00E-05 0.00E+00 6.95E-11 6.95E-11 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07
' 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.92E-08 1.00E-03 7.71E-07 2.58E-10 3.83E-09 3.00E-05 7.71E-07 7.73E-12 3.59E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.72E-09 1.00E-03 4.53E-08 1.51E-11 2.25E-10 3.00E-05 4.53E-08 4.54E-13 2.11E-10 Total 9.01E-03 1.00E-01 3.11E-05 1.05E-04 5.49E-06 1.00E-03 3.12E-05 1.05E-06 1.98E-07 3.00E-05 3.12E-05 3.16E-08 1.46E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
f i
e ' - -g - g - - - m-m
5-5 Table 5.2 Summary of Resuits for Pea h Bottom - Leak Test A0 Check Af ter Maintenance i
P(Rupture)
Line f(OP) S2 A CDF .
LPCI 3.53E-05 1.00E-01 3.47E-07 5.94E-07 5.96E-07 1.00E-03 3.53E-07 5.94E-09 7.58E-09 3.00E-05 3.53E-07 1.78E-10 1.82E-09 CS 2.94E-05 1.00E-01 2.94E-07 5.89E-09 7.25E-09 1.00E-03 2.94E-07 5.89E-11 1.42E-09 3.00E-05 2.94E-07 1.77E-12 1.37E-09 HPCI 1.64E-03 1.00E-01 0.00E+00 1.14E-07 1.14E-07 1.00E-03 0.00E+00 1.14E-09 1.14E-09 3.00E-05 0.00E+00 3.42E-Il 3.42E-11 RCIC 1.64E-03 1.00E-01 0.00E+00 1.14E-07 1.14E-07 1.00E-03 0.00E+00 1.14E-09 1.14E-09 3.00E-05 0.00E+00 3.42E-11 3.42E-Il Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-Il RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.92E-08 1.00E-03 7.71E-07 2.58E-10 3.83E-09 3.00E-05 7.71E-07 7.73E-12 3.59E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.72E-09 1.00E-03 4.53E-08 1.51E-11 2.25E-10 3.00E-05 4.53E-08 4.54E-13 2.llE-10 Total 4.34E-03 1.00E-01 1.43E-06 1.01E-04 9.74E-07 1.00E-03 1.46E-06 1.01E-06 1.65E-08 3.00E-05 1.46E-06 3.03E-08 7.08E-09 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
5-6 Table 5.3 Summary of Results for Peach Bottom - Logic System Functional Test at Shutdown Line f(OP) P(Rupture)
- f- S2 A CDF LPCI l.33E-05 1.00E-01 1.30E-07 3.00E-07 3.00E-07 1.00E-03 1.33E-07 3.00E-09 3.62E-09 3.00E-05 1.33E-07 8.99E-11 7.08E-10 CS 1.18E-05 1.00E-01 1.17E-07 1.52E-07 1.53E-07 1.00E-03 1.18E-07 1.52E-09 2.07E-09 3.00E-05 1.18E-07 4.56E-Il 5.95E-10 HPCI 1.68E-04 1.00E-01 0.00E+00 3.40E-08 3.40E-08 1.00E-03 0.00E+00 3.40E-10 3.40E-10
, 3.00E-05 0.00E+00 1.02E-11 1.02E-11 RCIC 1.68E-04 1.00E-01 0.00E+00 3.40E-08 3.40E-08 1.00E-03 0.00E+00 3.40E-10 3.40E-10 3.00E-05 0.00E+00 1.02E-11 1.02E-11 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12 E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 s RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.92E-08 1.00E-03 7.71E-07 2.58E-10 3.83E-09 3.00E-05 7.71E-07 7.73E-12 3.59E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.72E-09 1.00E-03 4.53E-08 1.51E-11 2.25E-10 3.00E-05 4.53E-08 4.54E-13 2.11E-10 Total 1.36E-03 1.00E-01 1.04E-06 1.01E-04 6.64E-07 1.00E-03 1.07E-06 1.01E-06 1.15E-08 3.00E-05 1.07E-06 3.02E-08 5.15E-09 l
Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
l 52 = Frequency of Unisolated Small LOCA (/ry).
l A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
i t
~
l i
5-7 Table 5.4
' Summary of Results for Peach Botton - Leak Test A0 Check in HPCI and RCIC at Refueling i
Line f(OP) P(Rupture) S2 f A CDP :
LPCI 1.52E-03 1.005-01 1.52E-05 2.66E-06 2.73E-06 1.00E-03 1.52E-05 2.66E-08 9.73E-08 3.00E-05 1.52E-05 7.99E-10 7.14E-08 -
CS 1.52E-03 1.00E-01 1.51E-05 2.08E-06 2.15E-06 1.00E-03 1.52E-05 2.08E-08 9.llE-08 3.00E-05 1.52E-05 6.23E-10 7.10E-08 HPCI
- 2.22E-03 1.00E-01 0.00E+00 1.54E-07 1.54E-07 1.00E-03 0.00E+00 1.54E-09 1.54E-09' 3.00E-05 0.00E+00 4.61E-11 4.61E-11 RCIC 2.22E-03 1.00E-01 0.00E+00 1.54E-07 1.54E-07 1.00E-03 0.00E+00 1.54E-09 1.54E-09 3.00E-05 0.00E+00 4.61E-11 4.61E-11 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2. 9 2'E-08 1.00E-03 7.71E-07 2.58E-10 3.83E-09 3.00E-05 7.71E-07 7.73E-12 3.59E-09 Vessel Head Spray 4.53E-OS 1.00E-01 4.38E-03 1.51E-09 1.72E-09 1.00E-03 4.53E-08 1.51E-11 2.25E-10 3.00E-05 4.53E-08 4.54E-13 2.11E-10 Total 8.49E-03 1.00E-01 3.llE-05 1.05E-04 5.33E-06 1.00E-03 3.12E-05 1.05E-06 1.97E-07 3.00E-05 3.12E-05 3.15E-08 1.46E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
in s '
5-8 Table 5.5 Summary of Results for Peach Bottom - /LL h deve b M k. .
Line : - f(OP) P(Rupture) S2 A CDF LPCI
' 8.88E-06 1.00E-01 8.73E-08 1.49E-07 1.50E-07 1.00E-03 8.88E-08 1.49E-09 1.90E-09 I 3.00E-05 8.88E-08 4.47E-11 4.57E-10 )
CS 7.40E-06 1.00E-01 7.40E-08 1.48E-09 1.82E-09 1.00E-03 7.40E-08 1.48E-11 3.58E-10 3.00E-05 7.40E-08 4.43E-13 3.44E-10 HPCI 5.05E-06 1.00E-01 0.00E+00 8.12E-10 8.12E-10 1.00E-03 0.00E+00 8.12E-12 8.12E-12 3.00E-05 0.00E+00 2.44E-13 2.44E-13 RCIC 5.05E-06 1.00E-01 0.00E+00 8.12E-10 8.12E-10 1.00E-03 0.00E+00 8.12E-12 8.12E-12 3.00E-05 0.00E+00 2.44E-13 2.44E-13 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.92E-08 1.00E-03 7.71E-07 2.58E-10 3.83E-09 3.00E-05 7.71E-07 7.73E-12 3.59E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.72E-09 1.00E-03 4.53E-08 1.51E-11 2.25E-10 3.00E-05 4.53E-08 4.54E-13 2.11E-10 Tota'l 1.03E-03 1.00E-01 9.50E-07 1.00E-04 2.96E-07 1.00E-03 9.79E-07 1.00E-06 7.46E-09 3.00E-05 9.79E-07 3.01E-08 4.63E-09 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Cora Damage Frequency (/ry).
l l
5-9
. Table 5.6 Summary of Results for Nine Mile Point Base Case Line - - f(OP) P(Rupture) S2 A CDF LPCI ~' 1.33E-05 1.00E-01 7.85E-06 2.24E-07 2.25E-07 1.00E-03 7.99E-06 2.24E-09 3.37E-09 ,
3.00E-05 7.99E-06 6.71E-11 1.20E-09 LPCS 3.69E-06 1.00E-01 2.22E-06 7.38E-10 1.05E-09 1.00E-03 2.22E-06 7.38E-12 3.21E-10 3.00E-05 2.22E-06 2.22E-13 3.14E-10 SDC Return 8 86E-06 1.00E-01 5.24E-06 1.49E-07 1.50E-07 1.00E-03 5.33E-06 1.49E-09 2.24E-09 3.00E-05 5.33E-06 4.47E-11 7.97E-10 HPCS 2.65E-07 1.00E-01 2.65E-07 3.25E-13 5.31E-11 1.00E-03 2.65E-07 3.25E-15 5.28E-11 3.00E-05 2.65E-07 9.75E-17 5.28E-11 Vessel Head Spray 4.35E-06 1.00E-01 5.05E-08 5.34E-11 2.74E-10 1.00E-03 5.05E-08 5.34E-13 2.21E-10 3.00E-05 5.05E-08 1.60E-14 2.20E-10 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 2
RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.58E-08 1.00E-03 7.71E-07 2.58E-10 3.41E-10 r
3.00E-05 7.71E-07 7.73E-12 9.10E-11 l Steam Condensing 8.90E-03 1.00E-01 1.73E-05 2.22E-04 2.22E-04
! 1.00E-03 1.78E-05 2.22E-06 2.23E-06
( 3.00E-05 1.78E-05 6.67E-08 6.86E-08 l Total 9.93E-03 1.00E-01 3.37E-05 3.23E-04 2.23E-04 1.00E-03 3.44E-05 3.23E-06 2.23E-06 l 3.00E-05 3.44E-05 9.68E-08 7.13E-08
( Notes: f(OP) = Frequency of Overpressurization (/ry).
- P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Fr( uency (/ry).
i r
4 l
5-10 Table 5.7 Summary of Results for Nine Mile Point Do Not Cycle F052 and F218 at Power I. '
Line i f(OP) P(Rupture) S2 A CDF :
LPCI 1.33E-05 1.00E-01 7.85E-06 2.24E-07 2.25E-07 1.00E-03 7.99E-06 2.24E-09 3.37E-09 3.00E-05 7.99E-06 6.71E-11 1.20E-09 LPCS 3.69E-06 1.00E-01 2.22E-06 7.38E-10 1.05E-09 1.00E-03 2.22E-06 7.38E-12 3.21E-10 3.00E-05 2.22E-06 2.22E-13 3.14E-10 SDC Return ,
8.86E-06 1.00E-01 5.24E-06 1.49E-07 1.50E-07 1.00E-03 5.33E-06 1.49E-09 2.24E-09 3.00E-05 5.33E-06 4.47E-11 7.97E-10 HPCS 2.65E-07 1.00E-01 2.65E-07 3.25E-13 5.3]E-Il 1.00E-03 2.65E-07 3.25E-15 5.28E-11 3.00E-05 2.65E-07 9.75E-17 5.28E-11 Vessel Head Spray 4.35E-06 1.00E-01 5.05E-08 5.34E-11 2.74E-10 1.00E-03 5.05E-08 5.34E-13 2.21E-10 3.00E-05 5.05E-08 1.60E-14 2.20E-10 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.58E-08 1.00E-03 7.71E-07 2.58E-10 3.41E-10
. 3.00E-05 7.71E-07 7.73E-12 9.10E-Il Steam Condensing 2.42E-03 1.00E-01 4.71E-06 6.04E-05 6.04E-05 1.00E-03 4.83E-06 6.04E-07 6.05E-07 3.00E-05 4.83E-06 1.81E-08 1.86E-08 Total 3.45E-03 1.00E-01 2.llE-05 1.61E-04 6.09E-05 1.00E-03 2.14E-05 1.61E-06 6.12E-07 3.00E-05 2.15E-05 4.82E-08 2.13E-08 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
n , .
5-11 Table 5.8 Summary of Results for Nine Mile Point Do Not Cycle F087 at Power Line I- f(OP) P(Rupture) S2 A CDF
- i -
LPCI 1.33E-05 1.00E-01 7.85E-06 2.24E-07 2.25E-07 1.00E-03 7.99E-06 2.24E-09 3.37E-09 3.00E-05 7.99E-06 6.71E-11 1.20E-09 '
LPCS 3.69E-06 1.00E-01 2.22E-06 7.38E-10 1.05E-09 1.00E-03 2.22E-06 7.38E-12 3.21E-10 3.00E-05 2.22E-06 2.22E-13 3.14E-10 SDC Return 8.86E-06 1.00E-01 5.24E-06 1.49E-07 1.50E-07 1.00E-03 5.33E-06 1.49E-09 2.24E-09 3.00E-05 5.33E-06 4.47E-11 7.97E-10 HPCS 2.65E-07 1.00E-01 2.65E-07 3.25E-13 5.31E-11 1.00E-03 2.65E-07 3.25E-15 5.28E-11 3.00E-05 2.65E-07 9.75E-17 5.28E-11 Vessel Head Spray 4.35E-06 1.00E-01 5.05E-08 5.34E-11 2.74E-10 1.00E-03 5.05E-08 5.34E-13 2.21E-10 3.00E-05 5.05E-08 1.60E-14 2.20E-10 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.58E-08 1.00E-03 7.71E-07 2.58E-10 3.41E-10 3.00E-05 7.71E-07 7.73E-12 9.10E-11 Steam Condensing 6.50E-03 1.00E-01 1.27E-05 1.62E-04 1.62E-04 1.00E-03 1.30E-05 1.62E-06 1.63E-06 3.00E-05 1.30E-05 4.87E-08' 5.01E-08 Total 7.53E-03 1.00E-01 2.90E-05 2.63E-04 1.63E-04
" 1.00E-03 2.96E-05 2.63E-06 1.63E-06 3.00E-05 2.96E-05 7.88E-08 5.28E-08 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
5-12
. Table 5.9 Summary of Results for Nine Mile Point Both Corrective Action i
Line ;I- f(OP) P(Rupture) S2 A CDF A .
LPCI ~I 1.33E-05 1.00E-01 7.85E-06 2.24E-07 2.25E-07 l.00E-03 7.99E-06 2.24E-09 3.37E-09 3.00E-05 7.99E-06 6.71E-11 1.20E-09 i
LPCS 3.69E-06 .1.00E-01 2.22E-06 7.38E-10 1.05E-09 1.00E-03 2.22E-06 7.38E-12 3.21E-10 3.00E-05 2.22E-06 2.22E-13 3.14E-10 l SDC Return 8.86E-06 1.00E-01 5.24E-06 1.49E-07 1.50E-07 1.00E-03 5.33E-06 1.49E-09 2.24E-09 3.00E-05 5.33E-06 4.47E-11 7.97E-10 i
HPCS 2.65E-07 1.00E-01 2.65E-07 3.25E-13 5.31E-11 1.00E-03 2.65E-07 3.25E-15 5.28E-11 3.00E-05 2.65E-07 9.75E-17 5.28E-11 Vessel Head Spray 4.35E-06 1.00E-01 5.05E-08 5.34E-11 2.74E-10
, 1.00E-03 5.05E-08 5.34E-13 2.21E-10 3.00E-05 5.05E-08 1.60E-14 2.20E-10 1 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07
! 1.00E-03 0.00E+00 1.00E-06 1.12E-09
, 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.58E-08 3 1.00E-03 7.71E-07 2.58E-10 3.41E-10 3.00E-05 7.71E-07 7.73E-12 9.10E-11 Stedm Condensing 1.62E-05 1.00E-01 3.14E-08 4.00E-07 4.00E-07 1.00E-03 3.22E-08 4.00E-09 4.01E-09 3.00E-05 3.22E-08 1.20E-10 1.24E-10
- Total 1.05E-03 1.00E-01 1.64E-05 1.01E-04 9.14E-07 1.00E-03 1.67E-05 1.01E-06 1.17E-08 3.00E-05 1.67E-05 3.02E-08 2.83E-09 Notes
- f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
i T
3
- - - ~ , _ . _ _ - _ _ , _ - _ _ _ , . _ _ _ _ . _ . _ _ _ . . . _ . _ . . _ -.._. _ -_ _ _ _ ________ _ _ _-_____ _ _______ _
4 5-13 Table 5.10
' Summary of Results for Quad Cities -Base Case Line 5- f(OP) P(Rupture) S2 A CDF b
~
LPCI E 2.07E-03 1.00E-01 2.07E-05 6.00E-06 6.11E-06 1.00E-03 2.07E-05 6.00E-08 1.71E-07 2.07E-05 1.80E-09 1.13E-07 l3.00E-05 '
CS 2.01E-03 1.00L-01 2.00E-05 3.04E-06 3.15E-06 1.00E-03 2.01E-05 3.04E-08 1.38E-07 3.00E-05 2.01E-05 9.13E-10 1.09E-07 HPCI 9.03E-04 1.00E-01 0.00E+00 9.42E-08 9.42E-08 1.00E-03 0.00E+00 9.42E-10 9.42E-10 3.00E-05 0.00E+00 2.82E-11 2.82E-11 RCIC 9.03E-04 1.00E-01 0.00E+00 9.42E-08 9.42E-08 1.00E-03 0.00E+00 9.42E-10 9.42E-10 3.00E-05 0.00E+00 2.82E-11 2.82E-Il Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Section 7.71E-07 1.005-01 7.45E-07 2.58E-08 2.97E-08 1.00E-03 7.71E-07 2.58E-10 4.39E-09 3.00E-05 7.71E-07 7.73E-12 4.14E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.75E-09 1.00E-03 4.53E-08 1.51E-Il 2.58E-10 3.00E-05 4.53E-08 4.54E-13 2.43E-10
{ Total 6.89E-03 1.00E-01 4.15E-05 1.09E-04 9.59E-06 1.00E-03 4.16E-05 1.09E-06 3.17E-07 3.00E-05 4.16E-05 3.28E-08 2.26E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
, P(Rupture) = Probability of Major Pipe Rupture.
l S2 = Frequency of Unisolated Small LOCA (/ry).
l A = Frequency of Large LOCA (/ry).
l CDF = Core Damage Frequency (/ry).
I
.= .... .
5-14 Table 5.11
, Summary of Results for Quad Cities - Leak Test A0 Check in ECCS Line :
f(OP) P(Rupture) S2 A CDF LPCI l.53E-03 1.00E-Oi 1.53E-05 6.00E-07 6.82E-07 1.00E-03 1.53E-05 6.00E-09 8.80E-08 3.00E-05 1.53E-05 1.80E-10 8.22E-08 CS 1.52E-03 1.00E-01 1.52E-05 3.04E-07 3.86E-07 1.00E-03 1.52E-05 3.04E-09 8.47E-08 3.00E-05 1.52E-05 9.13E-11 8.17E-08 HPCI 7.43E-04 1.00E-01 0.00E+00 7.45E-08 7.45E-08 1.00E-03 0.00E+00 7.45E-10 7.45E-10 3.00E-05 0.00E+00 2.24E-Il 2.24E-11 RCIC 7.43E-04 1.00E-01 0.00E+0G 7.45E-08 7.45E-08 1.00E-03 0.00E+00 7.45E-10 7.45E-10 3.00E-05 0.00E+C0 2.24E-11 2.24E-11 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.97E-08 4
1.00E-03 7.71E-07 2.58E-10 4.39E-09 3.00E-05 7.71E-07 7.73E-12 4.14E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.75E-09 1.00E-03 4.53E-08 1.51E-Il 2.58E-10 3.00E-05 4.53E-08 4.54E-13 2.43E-10 Total 5.54E-03 1.00E-01 3.13E-05 1.01E-04 1.36E-06 1.00E-03 3.13E-05 1.01E-06 1.80E-07 3.00E-05 3.14E-05 3.03E-08 1.68E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
A = Frequency of Large LOCA (/ry).
CDF = Cor? Damage Frequency (/ry).
- n. . . -
5-15 '
Table 5.12 Suumary of Results for Quad Cities - Leak A0 Check Af ter Maintenance Line -
f(OP) P(Rupture) S2 A CDF LPCI 1.87E-03 1.00E-01 1.87E-05 2.98E-06 3.08E-06 1.00E-03 1.87E-05 2.98E-08 1.30E-07 ,
3.00E-05 1.87E-05 8.95E-10 1.01E- 07 CS 1.81E-03 1.00E-01 1.81E-05 2.95E-08 1.26E-07 1.00E-03 1.81E-05 2.95E-10 9.71E-08 3.00E-05 1.81E-05 8.86E-12 9.68E-08 HPCI 8.02E-04 1.00E-01 0.00E+00 7.64E-08 7.64E-08 1.00E-03 0.00E+00 7.64E-10 7.64E-10 3.00E-05 0.00E+00 2.29E-11 2.29E-11 '
RCIC 8.02E-04 1.00E-01 0.00E+00 7.64E-08 7.64E-08 1.00E-03 0.00E+00 7.64E-10 7.64E-10 3.00E-05 0.00E+00 2.29E-11 2.29E-11 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.97E-08 1.00E-03 7.71E-07 2.58E-10 4.39E-09 3.00E-05 7.71E-07 7.73E-12 4.14E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.75E-09 1.00E-03 4.53E-08 1.51E-11 2.58E-10 3.00E-05 4.53E-08 4.54E-13 2.43E-10 Total 6.28E-03 1.00E-01 3.75E-05 1.03E-04 3.51E-06 1.00E-03 3.76E-05 1.03E-06 2.35E-07 3.00E-05 3.76E-05 3.10E-08 2.03E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
! S2 = Frequency of Unisolated Small LOCA (/ry).
l A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
l
5-16
~ Table 5.13 Summary of Results for Quad Cities - Both Corrective Actions Line :f- f(OP) P(Rupture) S2 A CDF
~ '
LPCI 1.51E-03 'l.00E-01 1.51E-05 2.98E-07 3.79E-07 1.00E-03 1.51E-05 2.98E-09 8.39E-08 3.00E-05 1.51E-05 8.95E-Il 8.10E-08 CS 1.50E-03 1.00E-01 1.50E-05 2.95E-09 8.35E-08 1.00E-03 1.50E-05 2.95E-11 8.06E-08 3.00E-05 1.50E-05 8.86E-13 8.06E-08 HPCI 7.38E-04 1.00E-01 0.00E+00 7.36E-08 7.36E-08 1.00E-03 0.00E+00 7.36E-10 7.36E-10 3.00E-05 0.00E+00 2.21E-11 2.21E-Il RCIC 7.38E-04 1.00E-01 0.00E+00 7.36E-08 7.36E-08 1.00E-03 0.00E+00 7.36E-10 7.36E-10 3.00E-05 0.00E+00 2.21E 2.21E-11 Feedwater 1.00E-03 1.00E-01 0.00E+00 1.00E-04 1.12E-07 1.00E-03 0.00E+00 1.00E-06 1.12E-09 3.00E-05 0.00E+00 3.00E-08 3.36E-11 RHR Suction 7.71E-07 1.00E-01 7.45E-07 2.58E-08 2.97E-08 1.00E-03 7.71E-07 2.58E-10 4.39E-09 3.00E-05 7.71E-07 7.73E-12 4.14E-09 Vessel Head Spray 4.53E-08 1.00E-01 4.38E-08 1.51E-09 1.75E-09 1.00E-03 4.53E-08 1.51E-11 2.58E-10 3.00E-05 4.53E-08 4.54E-13 2.43E-10 Total 5.49E-03 1.00E-01 3.09E-05 1.00E-04 7.54E-07 1.00E-03 3.09E-05 1.00E-06 1.72E-07 3.00E-05 3.09E-05 3.01E-08 1.66E-07 Notes: f(OP) = Frequency of Overpressurization (/ry).
P(Rupture) = Probability of Major Pipe Rupture.
S2 = Frequency of Unisolated Small LOCA (/ry).
l A = Frequency of Large LOCA (/ry).
CDF = Core Damage Frequency (/ry).
I
A-1
, APPENDIX A: Information Collected for Interfacing Lines A.1 Interfacing Lines at Peach Bottom l -
l The interfacing lines identified for Peach Bottom are the following:
- a. LPCI Injection Lines
- b. Shutdown Cooling Suction Line
- c. Reactor Pressure Vessel Head Spray
- d. Core Spray Injection Lines
- e. HPCI Pump Suction
- f. RCIC Pump Suction l These interfacing lines are shown in Figures A.1.a-A.I.f. Tables A.1.a-A.1.f list some data collected for them. Table A.I.g lists the lines
- penetrating the containment. The single character code in the first column of the table denotes the disposition of the line. An asterisk indicates that the
} line is considered in the study. A letter means that the line is not further considered, based on the screening criterion denoted by the same letter in Section 2.1.
A.1.1 LPCI Injection Lines The RHR system consists of two loops. Each loop consists of two heat 4
exchangers, two pumps, two suppression pool suction lines, and one injection line. The two loops are identical except that loop B has connections with high pressure service water and the fuel pool, and that loop A is connected to the vessel head spray. The discharge sides of the two loops are crossconnected with a closed deenergized valve, MO-10-20.
A.1.1.1 Automatic and Manual Control RHR pumps start autcmatically on low vessel level or high drywell pressure '
and low reactor pressure. The suction paths from the suppression pool are t
normally open. Outboard injection valve 154 is normally open.
i i
i
1 A-2 Inboard injection valve 25 is normally closed. When the automatic ;
actuation signal is present, an open signal is sent to the injection valves in both loops.I. Upon receiving the open signal, the normally closed injection '
) valves, 25A {and25B,willopenifthereactorpressureislow. A timer cancels,- ,
l the LPCI signals to the injection valve ~s,154A and 154B, af ter a delay time long enough to permit satisfactory operation of the LPCIS. The cancellation of the signals allows the operator to d.ivert the water for other post accident uses such as torus cooling, torus spray or drywell spray.
Without the low vessel pressure signal, the two injection valves in each loop are interlocked. One valve can be manually opened only if the other valve is closed.
A.l.1.2 Indications of Overpressurization or Interfacing LOCA In the event that the isolation valves 46 and 25 fail to isolate, the low pressure piping that will be overpressurized is bounded by valves 20, 25, 26, 33 (Loop A only), 39, 48, 177 (Loop B only), and 180 (Loop B only). The design pressure of the low pressure piping is 150 psi. There are two one-inch relief valves that discharge to the clean rad-waste system. When an interfacing LOCA occurs, the following indication may be available to the operators, in addition to the low vessel level alarm and the starting of the standby core cooling systems,
- 1. RHR Pump Room Flooding Alarm in the Control Room - Liquid level i
switches are set to detect water level 6" above the floor.
- 2. High RHR Room Ambient Temperature - Room temperature is alarmed and indicated in the control room.
- 3. Room ventilation temperature is indicated.
4 The reactor building drain sump pumps will start automatically on high level. .High high level in the drain sump also actuates an alarm in the main control room.
t
. i l A-3 t
- 5. - Righ pump discharge header pressure is alarmed in the control room.
- 6. Hih radiation in reactor building ventilation exhaust alarm in the conhrolroom. I
- 7. High RHR pump room rad ation and high reactor building sump area radiation alarms in the. control room.
A.1.2 Shutdown Heat Removal Suction from Recirculation A.1.2.1 Automatic and Manual Control Shutdown cooling is initiated manually when the nuclear system pressure has decreased to a point where the steam supply pressure is not sufficient to maintain the turbine shaft gland reals, and vacuum in the main condenser can not be maintained. Reactor coolant is pumped by the RHR pumps from one of the recirculation loops through the RHR heat exchangers. Reactor coolant is returned to the vessel via either recirculation loop. Part of the flow may be .
diverted to a spray nozzle in the reactor head. The isolation valves 17 and 18 can be manually opened in control room only if the vessel pressure is in shutdown cooling range. They receive automatic isolation signals on low vessel level or high drywell pressure or high vessel pressure (exceeding 625 psig).
A.1.2.2 Indications of Overpressurization or Interfacing LOCA In the case that the isolation valves 17 and 18 fail to isolate, the low pressure piping that will be overpressurized is bounded by valves 17, 520, 51, 15A, ISB, 15C, and 15D. Its design pressure is 150 psi. There is one one-inch relief valve in this pipe section that discharges to clean rad-waste system.
The indications for an interfacing LOCA are the same as those for LFCI lines, except that high suction pressure alarm replaces high discharge header pressure alarm.
., - - - , - ~-n-e,-
.,.n., -,-n.- , , - - . ,, ,, .---r
~
A-4 A.1.3 Vessel Head Spray A.1.3.1 Ms ual and Automatic Control t> :
Vessel head spray may be used in the shutdown cooling mode of the RHR system. Isolation valves 32 and 33 can be manually opened only if vessel pressure is in the shutdown cooling range. They receive an automatic isolation signal on low vessel level or high drywell pressure or high vessel pressure (exceeding 625 psig).
A.1.3.2 Indications of Overpressurization or Interfacing LOCA If the check valve down stream of the isolation valves as well as both isolation valves fails, the section of low pressure piping that will be overpressurized is the same as that for LPCI loop A. Therefore, the same indications will be available to the operators. The only difference is that both isolation valves in the head spray line receive automatic isolation signals.
A.1.4 Core Spray Injection Lines Core spray system consists of two identical loops. Each loop consists of two pumps with separate suction lines from the suppression pool.
A.1.4.1 Automatic and Manual Control Core spray pumps start on low vessel level sigaal or high drywell pressure and low vessel pressure. Each pump has a separate suction line from the suppression pool with the suction valve normally open. The tescable check valve, 13, and the inboard injection valve, 12, are normally closed. The outboard injection valve, 11, is normally open. Both injection valves open automatically when drywell pressure is high or vessel level is low and vessel pressure is low. Without automatic open signal, the two injection valves are interlocked. One valve can be opened only if the other valve is closed.
A-5 A.I.4.2 Indication of Overpressurization or Interfacing LOCA Ifthekaolationvalvesinthecoresprayinjectionlinesfailopen,the sectionorpfpingthatwillbeoverpressurizedisboundedbyvalves. 12, 10, 26, :
23, and 4225. This section has a design pressure of 450 psi. A two-inch relief }
valve is located in this pipe section. It discharges to clean rad-waste. When an interfacing LOCA occurs, in addition to the low vessel level alarm, the following indications will be available.
- 1. Core Spr y Pump Room Flooding Alarm in the Control Room - Liquid level _
switches are set to detect water level 6" above the floor.
- 2. The reactor building drain sump pumps will start automatically on high level. It also actuates an alarm in the main control room on high high level in the sump.
- 3. Pump discharge pressure and suction pressure are indicated locally.
- 4. A pressure switch is located between valves 11 and 12. An alarm in the control room will indicate the leakage through valves 12 and 13.
- 5. High radiation in reactor building ventilation exhaust alarm in the
- control room.
- 6. High core spray pump room radiation and high reactor building sump area radiation alarms in the control room.
A.I.5 HPCI Pump Suction A.1.5.1 Automatic and Manual Control The HPCI system is actuated on high drywell pressure or low vessel level.
Inboard injection valve 19 is normally closed and outboard injection valve 20 is normally open. Both valves receive an open signal on system actuation. They can be remote manually controlled from the control room. Pump suction from the
A-6 condensate storage tank is normally open. Suction valves 58 and 57 from the suppression pool are normally closed. They will be automatically opened when theCSTle.vk1'islow. After they are fully open, the suction valve, 17, from theCSTwilfbeclosedautomatically. Suction valves from the suppression pool :
and the two steam isolation velves are isolated by excess steam supply line space temperature or high steam supply line pressure differential.
A.1.5.2 Indication of Overpressurization or Interfacing LOCA If the feedwater inboard check valve (CV28A) and valves 18, 19, and 20 fail open, reactor coolant will overpressurize the piping on the suction side of the pump. It is bounded by valves 130, 131, 32, and 57. This pipe section has a design pressure of 150 psi. A one-and-one-half-inch relief valve is located in this section. It discharges to clean rad-waste.
If an interfacing LOCA occurs, in addition to low vessel level alarm, the following indications are available.
- 1. HPIC Pump Room Flo'oding Alarm in the Control Room - Level switches are set to detect water level 5" above the floor.
- 2. High HPCI Pump Room Temperature - High room temperature is indicated and alarmed in the control room, It also actuate isolation of the HPCI system which is also alarmed in the control room.
- 3. Room ventilation temperature is indicated.
- 4. The reactor building drain sump pump will start automatically on high level.
It also actuate an alarm in the control room on high high sump level.
- 5. Condensate storage tank low level alarm in the control room.
- 6. HPCI pump high suction pressure alarm in the control room.
J
A-7
- 7. High radiation in reactor building ventilation exhaust alarm in the control room.
- 8. High HPCI pump room radiation and high reactor building sump area I radiation alarms in the control room.
A.I.6 RCIC Suction - Reactor Core Isolation Cooling System A.I.6.1 Automatic and Manual Control The system is started on low vessel level. Suction path from the condensate storage tank is normally open. Its suction valve receives an open signal on system auto initiation. The outboard injection valves, 20, is normally open. The inboard injection valve, 21, is normally closed. Both l
, injection valves receive an automatic open signal on system auto initiation.
When CST level becomes low, automatic switch-over from CST to euppression pool will take place. After the suction valves from the suppression pool are fully 4
epen, the suction valve from the CST will be closed automatically.
4 A.I.6.2 Indications for Overpressurization or Interfacing LOCA 4
1 When inboard check valve (CV28B) and isolation valves 20, 21, and 22 fail open, the RCIC pump suction will be overpressurized. The overpressurized section is bounded by the RCIC pump and valves 39 and 19. .It has a design pressure of 150 psi. There is a one-inch relief valve in this pipe section. It discharges to clean rad waste. When an interfacing LOCA occurs in this pipe
'T section, in additica to the low vessel level alarm and the actuation of standby core cooling system, the following indications will be available.
- 1. RCIC Pump Room Flooding Alarm in the Control Room - Liquid level switches are set to detect water level 6" above the floor.
- 2. RCIC pump room temperature is indicated in the control room. High room i temperature is alarmed in the control room. It also isolate the RCIC system.
A-8
- 3. Room ventilation temperature is indicated.
I-
- 4. Thq reactor building drain sump pumps will start automatically. This '
is sindicated and alarmed in the control room of the rad-waste -
building. It also actuates an alarm in the main control room.
L. High RCIC pump suction pressure alarm in the control room.
- 6. Low CST level alarm in the control room.
- 7. High radiation in reactor' building ventilation exhaust alarm in the Control room.
- 8. High RCIC pump room radiation and high reactor building sump area radiation alarm in the control room.
i l
1 l
l
[
l i
i P = 1326 Psig P = 450 Psih , P = 450 Pstg ' P = 1135 Psiqy Une fill
__ Rv (toop A onty) -
_: 44 CV jf- MD
, Test top 1 2*
DC i oop A only)
Accunuta tor 43 33 -
MO g. MD MO R ecircula tion _ 24' 24' 12' Containnent ecottrrg I
- LD 46B ;,' 25B 154B 26B .
AD 16*
p uel pool (loop B only)
~
100 y
$Hlll-M-i Test top AF MD Suppression
- f 10 3' Pool 4DD qi 2D 39A i
Rue ux 2D
[ '
}RV35B ~~4 h
JL 3' 48B 24' I* 20' 2B HPSV (loop B only) 171 MD LOOP A 0
F10ure A.la LPCI (RHR) Injection lines. ,,
!fI llI! ,1l I 1! '
B D C A p p p p n n n n u u P P u u P
T
"' 9
" C C 9
li D l, A lI A
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s '
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7 ~
n w
1 2 o g
l l
= \ d t
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is b P l.
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1 e
- 1 r O 7 u
= M 1 g i
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ic e
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s e C y a y P r p e g 3
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6 P
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9 B
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A 8
A 3 S' o R
=
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( 2 y P
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e s
+ -
3 0
1
~
N vJ 7
l' 4
'i C
l F
p e
u a
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r I
- 4 C X A d P
=
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A 4 m '51 h
e e
g e M 6 2 = [ t e
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4
=
I m
r 1
V P =_ '
6 c 1
l.
- A 4
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I" 0
]
v c
3 4
5 h F r
u
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0 -
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- 2
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r o .1 - f
. 3 t
t a '4 3' X t
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m 1
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rs 1
- ep hn t u Op o 2 p
_ M 3 m u
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/
t e
s s
e V
l, 1
l j j
1 . ... I Twer w.
,P = 1135 Psig P = 450 Psig ,
Line felt e.
I 22A
- l. Accunulator __
l RV-20A 23A
, == \
AD -
,' MD MO n
- T
' 2* ~
' 2* N Vessel 7
/ '
,- AA 7N 12' /
N
> 12' 34
! 13A 12A 11A 63A 10A 1 - -
. Suppression AA _ _ _ Other pump l pool V7 10' 26A AC
,P = 150 Pstg
! l l Figure A.1d Core spray injection :ines.
j ..
Fron CST I _
.< > ~
P = 1500 Psig P = 150 Psig
< > 32 RV-34 AD MD J MD FE h n j ' DC IT,,
14' 3/4' qj , , 14, 3 14, g 16'
/
18 19 3f4./ 20
\ l I Y 3'
>I
, II y 4' ntniftow U FV 10' 28A II 96A Test y __ _
DC line 57 M k --
L ! Drain Y -
MD i Fron S.P.
FE 25 ] -
Figure A.le HPCI suction.
Fron CST CST HP, P = 1500 Pstg LP, P = 150 Psig
/N ( -~ MX / MD DC 30 }[-- MD ~
'N 19
~~
RV-25 RD --.
/ VM / I 6,
22 21 20 FE 2' Drywell y 39 3
_1 MD #
)N 0-y RD
) 39 l ',,W
~~
/96B M ain F V L _J DC 28B -
_ l Fron S.P.
29 S.P. ,
Figure A.1F RCIC suction.
A-15 Table A.I.a LPCI (RHR) Injection Lines i
- 1. 2 Numberfflines-
- 2. Line size - 24"
- 3. Valve number - 46A,B 25A,B*** 154A,B***
- 4. Valve location - I O O
- 5. Valve type - AO Check MO Gate MO Globe
~
- 6. Valve operator - air ac ac
- 7. Valve normal position - closed closed open 1
- 8. Power failure position - closed open
- 9. Isolation signals - * *
- 10. Normal flow direction - in in in
- 11. Surveillance requirement - + ** **
- 12. Pump surveillance requirement - manually started monthly, auto actuation / operating cycle, flow tested /
~
3 months
- 13. Relief valves - RV-35A,B 50 gpm at 425 psig, RV-44 50 gpm at 400 psig (Loop A only), and two 3" relief valves.
- Can be opened manually if reactor pressure is low or the other isolation valve is closed.
- Stroke tested monthly, actuation tested every operating cycle, LLRT/ cycle operational hydro test / cycle (25A, B only).
- Valves are interlocked.
+ Leak rate tested during operational hydro every cycle.
A-16 Table A.1.b Shutdown Cooling Suction (RHR)
I
- 1. Number'pf lines - 1 2.
.)
Line size - 20"
- 3. Valve number - 18 17
- 4. Valve location - in out 5.
Valve type - M0 Gate M0 Gate
. 6. Valve operator - ac dc
- 7. Valve normal position - closed closed
- 8. Power failure position - closed closed
- 9. Isolation signals - high drywell pressure or low vessel level or high vessel pressure
- 10. Normal flow direction - out out
- 11. Surveillance requirement - auto isolation / cycle, stroked / shutdown longer than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, LLRT/ cycle, operational hydro / cycle
- 12. Pump surveillance requirement - flow tested /3 months, manual started / month, auto actuation / cycle
- 13. Relief valves - four 1-inch relief valve, RV-72A-D 35 gpm at 158 psig, one 1-inch relief valve, and RV-40 35 gpm at 180 psig i
, ,_. . . - . . ~ _ _ _ ,__. , _ _ _ , _ . _ _ , _ . _ . _ _ _ _ _ . - . . . . _ -
A-17 Table A.I.c Vessel Head Spray (RHR)
- 1. Number' df lines -
1 i
- 2. Line size - 6"
- 3. Valve number - 32 33
- 4. Valve location - in in out
- 5. Valve type - check M0 MO
- 6. Valve operator - --
ac de
- 7. Valve normal' position - C C C
- 8. Power failure position - C C
- 9. Isolation signals - low vessel level or high drywell pressure or high vessel pressure
- 10. Normal flow direction - in in in
- 11. Surveillance requirement - stroked / shutdown longer than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, auto isolation / cycle, LLRT/ cycle
- 12. Pump surveillance requirement - flow tested /3 months, manual start /
month, auto actuation / cycle
- 13. Relief valves - KV-35A,B 50 gpm at 425 psig, RV-44 50
< gpm at 400 psig (Loop A only), and two 3" relief valves i
i
A-18 Table A.I.d Core Spray Injection Lines
- 1. Number' ' [f lines - 2
- k .
- 2. Line size - 12"
- 3. Valve number - 13A,B 12A,B*** 11A,B***
- 4. Valve location - I O O
- 5. Valve type -
A0 check. MO Gate MO Cate
- 6. Valve operator - air ac ac
. 7. Valve normal position - C C 0
- 8. Power failure position - C 0
- 9. Isolation signals - * *
- 10. Normal flow direction - in in in
- 11. Surveillance requirement - + ** **
- 12. Pump surveillance requirement - auto actuation test every operating cycle, flow test /3 month, manual start / month
- 13. Relief valves - RV-20A,B 120 gpm at 435 psig 4
- Can be opened only if reactor pressure is low or the other valve is closed.
- 0perability test / month, LLRT cycle, operational hydro test / cycle (12A, B only).
- Valves interlocked .
+ Cycle / month, operational hydrostatic test / cycle.
A-20 Table A.1.f RCIC Suction
?
- 1. Number p*~f lines - 1 g .
- 2. Line size - 6"
- 3. Valve number - 22 21 20*
- 4. Valve location - 0 0 0
- 5. Valve type - A0 check M0 MO
- 6. Valve operator - air de de
- 7. Valve normal position - C C 0
- 8. Power failure position - C 0
- 9. Isolation signals - none none
- 10. Normal flow direction - in in in
- 11. Surveillance requirement - + ** ***
- 12. Pump surveillance requirement - manual start every month, flow test /3 months auto actuation test at refueling
- 13. Relief valves - one 1-inch relief valve r
- Stroked / month, operational hydro test / cycle.
- Stro.ked/ month.
+ Stroked every shutdown greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
1
e Table A,1.g - ~
v; -~ Screening of Lin s Pznetrating Containment for Interfacing Lines at Peach Bottom
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Footnotes:
- Considered A - High energy line.
B - Small line < l-1/2".
C - Small < 3" and frequency of LOCA judged to be smalle D - Failure of PIVs.does not result in LOCA, frequency of LOCA .
Judged to be smalle E - Not connected to RCS. 1 A
e e
a ' -
A-23 A.2 Interfacing Lines at Nine Mile Point 2 The intqrfacinglinesidentifiedforNineMilePoint2arethefollowing:
- a. LPCI Injection Lines
- b. Shutdown Cooling Suction Line
- c. Reactor Pressure Vessel Head Spray
- d. Low Pressure Core Spray Injection Line
- e. HPCS Pump Suction.
- f. RCIC Pump Suction i
- g. Shutdown Cooling Return to Recirculation
- h. Steam Condensing Supply Line to RHR Heat Exchanger These interfacing lines are shown in Figures A.2.a-A.2.h. Tables A.2.a-A.2.h list some data collected for them. Table A.2.1 lists the lines penetrating the containment. The single character code in the first, column of the table denotes the disposition of the line. An asterisk denotes that the li.te is considered in the study. A letter means that the line is not further considered, based on the screening criteria denoted by the same letter in Section 2.1.
A.2.1 LPCI Injection Lines The RHR system concists of three loops. Each loop consists of one RRR pump and the associated valves and pipes. Loop C is used only in the LPCI mode.
Loop A and B are also used in other modes, e.g., shutdown cooling mode, steam condensing mode, and containment spray mode. They are identical and independent except the following:
- a. Suction line from the recirculation line is shared.
- b. Only loop B has a vessel head spray line.
- c. Only loop B has a service water connection.
- d. Loop C can not be used for fuel pool cooling.
- e. The steam line from the RCIC system is shared.
, - _ _ _ - -..- - - .- - . - . - - - - _ = _ , _ . _ , -
,, 7 ,
A-24
- A.2.1.1 Automatic and Manual Control -
The LF mode of RHR system is actuated automatically on high drywell pressure an low vessel level. The three RHR pumps will start automatically and I the injection valves F042A, B, and C will open when the pressure difference across them is i 130 psid. The suction valves from the suppression pool are i are normally key locked open. To ensure proper system lineup, the following normally closed valves are signaled to close.
E I a. MO F026A, B and A0 F065A, B in RHR heat exchanger discharge to RCIC l suction.
- b. MO F011A and B in RHR heat exchanger flush to suppression pool.
- c. RHR heat exchanger steam pressure reducing valves A0 F051A and B.
- d. RHR heat exchanger steam inlet isolation valves MO F052A and B and F087A and B.
- e. MO F024A, B and F021 in test return line to the suppression pool,
- f. Containment spray to suppression pool valves MO F027A and B.
j g. Steam condensing mode drain line valves F106A and B, and F107A and B.
- h. RRR sample valves F060A and B, and F025A and B.
) The LPCI pump motors and injection valves have manual override control that 1
permit the operator to manually control the system subsequent to automatic i initiation.
i A.2.1.2 Indications of Overpressurization or Interfacing LOCA In the case that the isolation valves F041 and F042 fail to isolate, the low pressure piping that will be overpressurized is bounded by valves F042, F021, F053, F063 F025, F016, F027, F023, F086, F024, F049, F089B, F060, F065, F031, F080, F055, F087, F051, F072, F085, and F074, thermal relief valve on heat exchanger vessel. Valve F089B applies only to RHR pump B. For RHR pump C which does not have a heat exchanger the low pressure piping that will be overpressurized is bounded by valves F042, F063, F025, F021, F085, and F031.
The design pressure of this section is 500 psig. There are two relief valves in this pipe section. Their combined capacity is approximately 185 gpm.
Indications of overpressurization or interfacing LOCA are the following:
s i
i
A-25
- 1. RRR pump discharge abnormal pressure alarm in the control room.
- 3. EihhRHRpumproomambienttemperaturealarminthecontrolroom.
- 4. F* reactor building ventilation exhaust radiation alarm in the :
conicol room.
f A.2.2 Shutdown Cooling Suction I
A.2.2.1 Automatic and Manual Control The suction valves F009 and F008 have pressure interlock so that a valve can not be opened if the inboard -pressure is high. They are used during the shutdown cooling mode. Va'lves F006A and B further down stream are normally closed and are interlocked so that a valve can be opened only if the corresponding suppression pool suction valve is closed.
l A.2.2.2 Indications of Overpressurization or Interfacing LOCA If isolation valves F008 and F009 fail open, the low pressure piping that 4
will be overpressurized is bounded by valves F008, F007, F005, F006A, and l F006B. The design pressure of the section is 220 psig. A relief valve F005 is
] located in this section. High pressure in this pipe section is alarmed in the control room. If an interfacing LOCA occurs, the following indications will be l
- available, in addition to low vessel level alarm:
r j 1. High shutdown suction pressure alarm in the control room.
l 2. High RHR pump room sump level alarm in the control room.
- 3. High RHR room ambient temperature alarm in the the control room. It
, also sends an isolation signal to the following valves.
- a. RHR shutdown return valves F053A and B.
- b. RHR shutdown return line inboard bypass valve F099A and B.
- c. RHR. shutdown suction valves F008 and F009.
- d. RCIC steam supply valves F063 and F064.
4
A-26
- e. RCIC steam supply bypass to inboard isolation valves F076.
- f. .RER head spray valve F023.
- 4. High reactor building ventilation exhaust radiation alarm in the conkrolroom.
- 5. High RHR heat exchanger equipment room radiation alarm in the control room.
A.2.3 Reactor Vessel Head Spray A.2.3.1 Manual and Automatic Control i
Vessel head spray is used in the shutdown cooling mode of the RHR system.
Isolation valve F023 can be manually controlled. It receives automatic isolation signal on low vessel level, high RPV pressure or high area ambient temperature.
A.2.3.2 Indications of Overpressurization or Interfacing LOCA If the check valves, upstream of the isolation valve F023, as well as valve F023 fail, the section of low pressure piping that will be overpressurized is the same as that for LPCI line. Therefore, the same indications will be available to the operators. The only difference is that the isolation valve F023 in the head spray line receive automatic isolation signals.
A.2.4 Low Pressure Core Spray Injection Line A.2.4.1 Automatic and Manual Control Core spray pump starts automatically on high drywell pressure or low vessel level. A "close" signal is also sent to MOV F012 in the test return line. The injection valve, F005, is normally closed. It can be opened manually or automatically only if the pressure difference across it is 1 88 psid. The testable check valve, F006, is designed for remote opening with zero differential pressure across the valve seat. It will close on reverse flow even though the test switches may be positioned for open. The suction valve, F001, is normally open and can be operated with a key lock switch in the control room.
Ar27 A.2.4.2 Indication of Overpressurization or Interfacing LOCA Ifisolktionvalves,F005andF006failopen,thesectionofpipingthat wilibeoverhressurizedisboundedbyvalvesF005,F018,F075,F003,F012,F004,:
and 7034. Tts design pressure is 550 psig. A relief valve, F018, is located in this section. Yte following indications are available to the operators, in addition to high drywell pressure and low vessel level:
- 1. High core spray pump discharge pressure alarm in the control room. The discharge pipe between the discharge check valve, F003, and the injection valve, F005, is normally filled with water by a line-fill pump that takes suction from the core spray pump suction. High or low pressure is alarmed in the control room.
- 2. High core spray pump room sump level alarm in the control room.
- 3. High reactor building ventilation exhaust radiation alarm in the control room.
A.2.5 HPCS Pump Suction A.2.5.1 Automatic and Manual Control The HPCS pump starts automatically on low vessel level or high drywell pressure. Upon actuation, the normally open suction valve from the condensate storage tank is signaled to open, the test return valves F010, F011, and F023 are signaled to close, the normally closed injection valve F004 is signaled to open. The suction valve, F015, from the suppression pool is normally closed and
- will open automatically when the CST level is low or the suppression pool level l is high. After valve F015 is fully opened, the suction valve from the CST is closed automatically. The injection valve will close automatically when the vessel level reaches level 8. The water leg pump keeps the pipe section between the discharge check valve and the injection valve filled. Low pump discharge 1
pressure is alarmed in the control room. The HPCS pump discharge check valve is located below the minimum suppression pool leiel and the pipe section between the pump and the. check valve is normally filled with water.
A-28 A.2.5.2 Indications of Overpressurization or Interfacing LOCA IfcoddninmentisolationvalvesF004andF005failopen,thepipesection thatwillbhpressurizedisboundedbyvalvesF004,F003,F010,F023,F024, -
F006, F035, and F026. This section is high pressure designed. Therefore, no overpressurization occurs, additional valve failures must occur to result in overpressurization. If HPCS discharge valve also fails open, then the low pressure piping on the, suction side will be overpressurized. The overpressurization is bounded by valves F002, F016, F019, F035, F014, and the HPCS pump. There is a 10 gpm capacity relief valve in this pipe section that discharges to the suppression pocl. If an interfacing LOCA occurs as a result of overpressurization the following indications may be available to the
, operators, in addition to the low vessel level alarm:
- 1. High HPCS pump suction pressure alarm in the control room.
- 2. Low condensate storage tank level alarm in the control room.
- 4. High reactor building ventilation exhaust radiation alarm in the control room.
A.2.6 RCIC Pump Suction A. 2. 6.1' Automatic and Manual Control The RCIC system is actuated automatically on low vessel level. The actuation signal sends an open signal to the injection valve F013, the pump I
suction valve F010 from the condensate storage tank, and the steam supply valve F045. It also sends a close signal to the normally closed test return valve F022. The steam supply valve F045 is normally closed and can be opened if the turbine exhaust valve F068 is fully open. The injection valve F013 is normally closed and can be opened automatically if the steam supply valve F045 is not fully closed. It can be manually closed with valve F045 closed. The pump suction from condensate storage tank F010 is normally open and will close automatically when the suction valve F031 from the suppression pool is open.
I
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A-29 The RCIC system is connected with the RHR system at three locations. In the steam condensing mode of RHR system, steam is taken from the RCIC steam supplylinebutsidethedrywell. The condensate from the RHR heat exchangers can be suppkhed to the RCIC pump suction through normally closed valves F026A and B. The discharge from RHR pump B is connected with the RCIC vessel head spray line outside the drywell.
When the vessel level reaches level 8, the steam supply valve F045 will close automatically, which will cause the injection valve F013 to close. The following isolation signals will close the turbine trip and throttle valve which will cause the injection valve to close.
- a. High RCIC pump suction pressure.
- b. RHR equipment area high temperature.
- c. RCIC pipe routing area high temperature.
- d. RCIC equipment area high temperature.
- e. Steam supply pressure low.
- f. Steam line high differential pressure.
- g. Instrument line break.
- h. Turbine exhaust diaphragm pressure high.
A.2.6.2 Indications of Overpressurization or Interfacing LOCA If valves F066, F065, and F013 fail open, the reactor pressure will overpressurize the suction side of the RCIC pump. The overpressurization is bounded by valves F013, F006, F022, F011, F061, F026A, F026B. F030, F057, and F019. The design pressure of the pump suction is 100 psig. Three relief valves F036, F017, and F018 are located in the section. If an interfacing LOCA occurs, the following indications will be available, in addition to the low vessel level alarm:
- 1. High RCIC pump suction pressure alarm in the control room.
- 3. High reactor building ventilation exhaust radiation alarm in the control room.
A-30
- 4. High RCIC room temperature alarm in the control room. It will also isolate the RCIC system by closing the steam supply isolation valves F0(3,F064,andtheturbinetripandthrottlevalve. After the turbine trfp and throttle valve is fully closed, the injection shutoff valve :
F013 will close automatically.
A.2.7 Shutdown Cooling Return to Recirculation A.2.7.1 Automatic and Manual Control The shutdown cooling mode of the RHR system is initiated manually after the reactor pressure is 95 psig or less. This condition can be reached approximately 1-1/2 hours after shutdown with the maximum cooldown rate of 100*F/hr. The suppression pool suction valve is closed. The piping is flushed
- and prewarmed by opening the bypass valve of the testable check valve and the suction valves from the recirculation line. The RHR pump is then started with the heat exchanger bypass valve open and the heat exchanger valves closed. The service water valves and the heat exchanger valves are opened a few minutes later. Valves F053 and F048 are used to control the cool down rate. The 4
containment isolation valve F053 receives automatic isolation signal on low vessel level, high vessel pressure and high RHR equipment room ambient temperature.
l, i A.2.7.2 Indications of Overpressurization or Interfacing LOCA If the isolation valves F050 and F053 fail open, the low pressure piping that will be overpressurized is identical to that for a LPCI line (see Figure A.2.al). The same indications will be available.
- A.2.8 RHR Steam Condensing Supply Line A.2.8.1 Automatic and Manual Control The steam co.ndensing mode of the RHR system can be manually initiated 1-1/2 hours after a reactor trip. It is capable of condensing all the steam generated. It takes steam from the RCIC steam line outside the drywell and I
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A-31 condenses it in the RHR heat exchangers. The condensate can be returned to the RCIC suction or the suppression pool. The containment isolation valves for this linearenor4allyopen. The automatic isolation signals are shown in Table A.2h. ,f '
A.2.8.2 Indications of Overpressurization or Interfacing LOCA If the pressure isolation valves F052 and F051 or F087 fail open, the low pressure piping that will be overpressurized is the same as that for LPCI lines. Therefore, the same indications will be available to the operators. The only difference is that the containment isolation valves F063 and F064 should close upcn automatic isolation signals.
9
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Figure A.2b Shutdown cooling suction.
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A-40 4
Table A.2.a LPCI Injection Lines
- 1. Number of lines - 3 ,
.p -
- 2. Line size - 12"
- 3. Valve number - F041(16) F042(24)
- 4. Valve location - in out
- 5. Valve type - A0 check MOV
- 6. Valve operator - (air) ac
- 7. Valve normal position - C C
- 8. Power failure position - C
- 9. Isolation signals - None *
- 10. Normal flow direction - in in
- 11. Surveillance ** ***
requirement -
- 12. Pump surveillance requirement - Flow test /3 month, auto actuation / 18 months
- 13. Relief capacity & F025 10 gpa at 470 psig setpoint - F055 97000 lb/hr at 500 psig
- *Can be opened only if the pressure difference across the valve is f 130 psid.
- Stroked every cold shutdown if not stroked in 92 days, LLRT/18 months, leak test /18 months and after cycling.
- Stroked every cold shutdown if not stroked in 92 days, position verification / month, auto actuation /18 months, LLRT/18 months, PIV leak test /18 months and after cycling.
1
A-41 Table A.2.b Shutdown Cooling Suction
- 1. Number pf lines - 1
.,i
- 2. Line size - 20"
- 3. Valve number - F009(112) F008(113)
- 4. Valve location - in out
Valve operator - ac ac l 7. Valve normal position - C C
- 8. Power failure position - C C
- 9. Isolation signa'Is * *
- 10. Normal flow direction - in in
- 11. Surveillance ** **
requirement -
1
- 12. Pump surveillance requirement - Flow test /3 month, auto actuation / 18 months l 13. Relief capacity &
setpoint - F005 1 gpm at 200 psig
- Low vessel level, high vessel pressure, high area ambient temperature.
- Position verification / month, LLRT/18 months, PIV leak test /18 months, stroke at cold shutdown if not stroked in 92 days.
4 d
6 .
i
- . - - . . . . - - _ . - - - . - - - . . - - - . - - - - . , _ - . _ -.. .-. - - - -.-- - -~- . - .
A-42 Table A.2.c Vessel Head Spray (RCIC)
- 1. Number f lines - 1
- 2. Line s ze - 6"
- 3. Valve number - F066(157) F065(156) F013(126) r
- 4. Valve location - in out out
- 5. Valve type - Check Check MO
- 6. Valve operator - air air dc
, 7. Valve normal' position - C C C
- 8. Power failure position - - -
C
- 10. Normal flow direction - in in in
- 11. Surveillance * * **
requirement -
- 12. Pump surveillance Flow test /3 month, auto actuation /18 months requirement -
- 13. Relief capacity & F036 465 gpm at 125 psig setpoint - F017, F018
- LLRT/18 months.
[ **LLRT/18 months, stroke at cold shutdown if not stroked in 92 days, position verification / month, auto actuation /18 months.
l i
A-43 Table A.2.d Low Pressure Core Spray Injection Line i
- 1. Number pf lines - 1
.4 -
- 2. Line size - 12"
- 3. Valve number - F006 F005
- 4. Valve location - I O
- 5. Valve type - A0 check MO gate
- 6. Valve operator - (air) ac
- 7. Valve normal position - C C
- 8. Power failure position - -
C
- 9. Isolation signals - None *
- 10. Normal flow direction - in in
- 11. Surveillance *** - **
requirement -
- 12. Pump surveillance requirement - Flow test /3 month, auto actuation / 18 months
- 13. Relief capacity &
setpoint - F018 100 gpm at 600 psig
- Can be opened only if pressure differential across the valve is i 130 paid.
- Position verification / month, auto actuation /18 months, LLRT/18 months, PIV leak test /18 months stroked at cold shutdown if not atroked in 92 days.
- Stroked at cold shutdown if not stroked in 92, days, LLRT/18 months, PIV leak tent /18 months.
A-44
~
, Table A.2.e HPCS Pump Suction
- 1. Numbei of lines - 1
- 2. Line size - 12" 2
- 3. Valve number - F005 F004 4 Valve location - in out l 5. Valve type - A0 check MO gate
[
- 6. Valve operator - (air) ac I 7. Valve normal position - C C
- 8. Power failure
- position - -
C l
l 9. Isolation signals - None None f 10. Normal flow i
direction - in in i
- 11. Surveillance **
- requirement -
l
- 12. Pump surveillance requirement - Flow test /3 month, auto actuation / 18 months at refueling i 13. Relief capacity & F035 at 1525 psig setpoint - F014 10 gpm at >100 psig I
)
- Position verification / month, auto actuation /18 months, LLRT/18 months, PIV leak test /18 months stroked at cold shutdown if not stroked in 92 days.
- LLRT/18 months, PIV leak test /18 months.
l l
A-45
~,
Table A.2.f RCIC Pump Suction 5
1.
Numbeihflines-1 ,
- 2. Line size - 6" ,
- 3. Valve number - F066(156) F065(157) F013(126) t
- 4. Valve location - in out out 5.
Valve type - A0 check A0 gate MO
- 6. Valve operator - (air) (air) de
- 7. Valve normal position - C C C
- 8. Power f ailure position - - -
C
- 9. Isolation signals - None None *
- 10. Normal flow direction - in in in
- 11. Surveillance ** ** ***
requirement -
- 12. Pump surveillance Flow test /3 month, auto actuation / 18 months if not tested requirement - in past 92 days
- 13. Relief capacity & F036 465 gpa at 125 psig .
setpoint - F017, F018
- It will close automatically if either the turbine steam supply valve or the turbine trip and throttle valve is closed.
- Auto actuation /18 months, LLRT/18 months, PIV leak test /18 months, stroked / cycle at cold shutdown if not tested in past 92 days or refueling.
- Position verification / month, auto actuation /18 months stroked / cycle at cold shutdown if not tested in past 92 days or refueling.
A-46
~, Table A.2 3 Shutdown Cooling Return to Recirculation a
- 1. Numbei f lines - 2
- 2. Line size - 12"
- 3. Valve number - F050(39) F053(40)
- 4. Valve location - in out i
- 5. Valve type - A0 check MOV
- 6. Valve operator - (air) ac
- 7. Valve normal '
position - C C
- 8. Power failure position - -
C
- 9. Isolation signals - None *
- 10. Normal flow direction - in in
- 11. Surveillance ** ***
requirement -
- 12. Pump surveillance requirement - Flow test /3 month, auto actuation / 18 months
- 13. Relief capacity & F025 10 gym at 470 peig setpoint - F055 97000 lb/hr at 500 psig
- Low vessel level or high reactor pressure or high area ' temperature.
- LLRT/18 months, PIV leak test /18 months strok/ cold shutdown, 92 days.
- LLRT/18 months, PIV leak test /18 months, strok/ cold shutdown if not tested in 92 days, position verification / month.
l
A-47
~
Table A.2.h RHR Steam Condensing Supply Line
- 1. Number 'df lines - 1
. n .
- 2. Line size - 8" 4
- 3. Valve number - F087(23) F052(23) F218(80) F051(21) F063 F064 F076
- 4. Valve location - out out out out in out in
- 5. Valve type - Globe . Globe Globe Diaph. Gate Cate Globe l 6. Valve operator - ac ac ac air ac ac ac i
, 7. Valve normal * '
l position - C C C C 0 0 C
- 8. Power failure position - C C C C 0 0 0
- 9. Isolation signal ~s - * * *
- 10. Normal flow direction - out out out out out out out
- 11. Surveillance ** ** **** ** *** *** ***
requirement -
I
- 12. Pump surveillance Flow test / month, auto actuation /18 months requirement -
- 13. Relief capacity & F025 10 gpa at 470 psig setpoint - F055 97000 lb/hr at 500 psig
supply pressure, high steam line differential pressure, high RCIC turbine exhaust diaphragm pressure, high RHR equipment area temperature.
- PIV leak test /18 months after maintenance, after cycling.
- LLRT/18 months.
i ****PIV leak test /18 months, after maintenance, after cycling, stroke /3 months at 3
power.
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A-64 A.3 Interfacing Lines at Quad Cities t I The interfacing lines identified for Quad Cities are the following: t ,
-e
- a. Shutdown Cooling Suction Line
- b. Reactor Pressure Vessel Head, Spray
- c. LPCI Injection Lines
- d. RCIC Pump Suction
- e. Core Spray Injection Lines
- f. HPCI Pump Suction The interfacing lines are shown in Figures A.3.a-A.3.d. Tables A.3.1-A.3.8 list some data collected for them. Table A.3.9 lists the lines penetrating the containment. 'The single character code in the first column of the table denotes the disposition of the line. An asterisk denotes that the lina is considered in the study. A letter means that the line is not further considered. based on the screening criterion denoted by the same letter in Section 2.1.
d A.3.1 RHR-Reactor Shutdown Cooling A.3.1.1 Automatic and Manual Control The shutdown cooling mode of the RHR system is manually initiated from the control room and the two normally closed suction valves (1001-47 and 1001-50) leading to the RHR pumps are interlocked with RPV pressure. These valves can not be signaled open unless vessel pressure is at or below 100 psi. These valves perform the containment isolation function, from there the line splits into four lines and there is a third valve in each leg which then feeds one each of the four RHR pumps (see Figure A.3.a). The two isolation valves will automatically close on low reactor water level "A" or high RPV pressure (see Table A.3.1). A.3.1.2 _ Indications of Overpressurization or Interfacing LOCA J. The RHR shutdown cooling line is a 20" line from the B recirculation loop. This line becomes a low pressure line just downstream of the second isolation
A-65 valve (MOV 47). The low pressure piping that is vulnerable to full reactor pressure is bounded by the second isolation valve on one end and by the four normally el sed RHR pump suction valves (MOV's 43A, B, C, and D) on the other. , This section of piping is protected from moderate pressure excursions by a 1" ' pipe feeding a 1-1/2" valve set at 150 psig. Failure of this piping creates an unisolable LOCA outside the primary containment and all inventory out the break will be lost to the suppression pool for subsequent recirculation. :Because MOVs 43A, B, C, and D are normally closed, the LPCI function of the RHR system will not be directly affected (i.e., the necessary piping will be intact). However, further information must be obtained from Quad Cities before a definitive statement can be made as to any failures that may occur due to the blowdown itself. High spa *cc temperature alarms are provided along the shutdown cooling line to alert the operator to a break or leak in this line. It is not currently known if the instrumentation is qualified to function in the presence of the blowdown from an interfacing system LOCA. A.3.2 Reactor Pressure Vessel Head Spray A.3.2.1 Automatic and Manual Control The reactor head spray line is used as part of the reactor shutdown cooling mode of the RHR systems. There are two normally closed motor-operated isolation valves in this line that can be opened manually from the control room when vessel pressure is less than 100 psi. There is also a check valve located downstream of the two isolation valves and nearest to the vessel (see Figure A.3.a).The two isolation valves will automatically close on either reactor low water level "A" or high reactor pressure (see Table A.3.2). A.3.2.2 Indications of Overpressurization or Interfacing LOCA The reactor head spray line is a 4" line that becomes low pressure just upstream of the two isolation valves (MOVs 60 and 63). The section of low pressure piping exposed by the failure of check valve 64 and the two isolation valves is protected by five relief valves. RV-59 is the first valve ec. countered
A-66 and is a 1" line set at 406 psig. The next two relief valves are on the loop A andloopB}8" headers (RV-22AandB,respectively)andareboth1"valvesset at 408 psig" In parallel with RV-22A and B are the two RHR heat exchanger relief valves (RV-166A and B). These valves are each 1" with a setpoint of 450 psig. For this particular 4" line', there would appear to be sufficient relief capacity to possibly prevent any pipe / equipment damage. However, in order to use the LPCI system, the loop crosstie would have to be closed by the operator so that the A loop would be isolated from the blowdown and the A loop relief , valves would have to reseat. Operator awareness of this event could come from the high space temperature alarms associated with this line; however, with no line break, the temperature rise could be slow. LPCI loop B piping can not be isolated from the interfacing valve failures. Depending on the actual failure modes of these valves, loop B may be rendered partially to fully impaired. A.3.3 LPCI Injection Lines A.3.3.1 Automatic and Manual Control There are two LPCI injection lines and these lines are also used during the reactor shutdown cooling mode. The valve lineup for each line consists of an air operated check valve inside the drywell, a normally closed motor operated gate valve just outside the drywell and then, a normally open motor operated l globe valve as the outboard isolation valve (see Figure A.3.a). The two series l MOVs can be opened manually from the control room or automatically upon a safeguards initiation, however, RPV pressure must be below 375 psi. k A.3.3.2 Indications of Overpressurization or Interfacing LOCA The LPCI lines are 16" and each comes off its own 18" header. the only , difference between loop A and loop B is that the vessel head spray line also comes off the B header. Failure of the check valve and normally closed MOV will overpressurize b'oth loops of LPCI as they are connected through a normally open
. ~ .. . - , . - .
A-67 18" crosstie line. Each header has a relief valve sized at 1" and set at 408 psig. Theyesselheadspraylinereliefvalve(RV-59)isalso1"andsetat408 psig. Thei iping back to the RHR pump discharge check valves will also be overpressurtzed. In each of these lines is a 1" relief valve on the RHR heat I exchangers that will also provide some protection for this event. Given a small LOCA event, both LPCI loops are assumed unavailable due to the open crosatie piping. A.3.4 RCIC Pump Suction A.3.4.1 Automatic and Msnual Control The RCIC injection line feeds into the feedwater line at a point upstream of that It'nes' containment isolation valves. Therefore, in order to have an interfacing system LOCA, the two normally open (during operation) feedwater isolation valves (check valves) must fail to close in addition to the overpressurization failure of the RCIC system (see Table A.3.5). The valve f lineup in the RCIC injection line consists of an air operated check valve, a normally closed MOV and a normally open MOV with both MOVs utilizing de power (see Figure A.3.b). Both MOVs are automatically signaled to open on reactor vessel low level. These valves may also be opened or closed by remote manual switches (see Table A.3.4). No information has been found concerning the automatic closing of these two MOVs. [The steam supply line to the RCIC turbine requires containment isolation protection and thereby receives the attention in the FSAR.] A.3.4.2 Indications of Overpressurization or Interfacing LOCA Overpressurization of the low pressure RCIC pump suction piping would be alarmed in the control room. There is also a pressure indicator for that line in the control room. The 6" suction line is protected by a 1" relief valve set at 150 psig. The low pressure piping is bounded by the pump on one end and by ! closed valves to the two possible suction sources the CST (closed valve) and , i supprersion pool (N.C. MOV). Area radiation monitoring is also available in the RCIC pump room.
,t A-68 A.3.5 Core Sprav Injection Lines
~
_i A.3.5.1 Aa(6matic and Manual Control s ~ The core spray system is part of the ECCS and is not used under normal circumstances. There are two core spray lines which feed directly into the reactor. The valve lineup from;the vessel outwards includes an air operated
- check valve inside the drywell,
- a normally closed MOV and then a normally open I MOV both outside the drywell (see Figure A.3.c). Both MOVs receive automatic open signals upon either low-low reactor water level or high drywell pressure, however, these isolation valves are interlocked so that they can not be opened (if closed) unless vessel pressure is below approximately 350 psi. Both sets of valves can be manually controlled from the control room (see Table A.3.6).
A.3.5.2 Indications of Overpressurization or Interfacing LOCA 4 There is a pressure sensor < upstream of the inboard isolation valve (MOV 25A, B) which is set to provide :an alarm on high pressure and there is a 2" relief valve set at 475 psig upstream o'f the outboard isolation valve. The vulnerable piping is from the upstream isolation valve (MOV 24A, B) back through to the pump discharge stop check valves (8A and 8B). A.3.6 HPCI Pump Suction A.3.6.1 Automatic and Manual Control The HPCI injection line feeds into the feedwater line upstream of that lines containment isolation valves. Therefore, in order to have an interfacing system LOCA, the two normally open (during operation) feedwater isolation valves (check valves) must fail to close in addition to the overpressurization failure of the HPCI system (see Table A.3.8). The HPCI valve lineup from the feedwater line to the pump consists of an-air operated check valve, a normally closed MOV and a normally open MOV (see Figure A.3.d). Both MOVs are automatically signaled to open'upon reactor vessel low level or high drywell pressure. The normally closed inboard isolation valve is also automatically signaled to close signaled to trip (see Table A.3.7). Automatic tripping of the HPCI turbine
o . i A-69 i i occurs when either of two high turbine exhaust pressure switches are actuated, or two reactor high water level switches are both actuated, or on low HPCI pump sectionpeqsure,however,thesetrippingmechanismsareonlyactivewhenthe turbine stdp valve is open (i.e., the pump is operating). I The HPCI injection line has undergone a recent design modification in which a new safe shutdown system had been added. The safe shutdown system consists of one motor-operated pump and functions in a similar manner to the RCIC. The one pump is capable of injecting into either units' HPCI injection line upstream of the HPCI air-operated check valve (see Figure A.3.d). The system configuration from the pump consists of a discharge check valve and a normally closed motor operated globe valve, then the line splits into two lines (one to each unit) and these two lines each have a normally closed gate valve and a check valve. This configuration yields seven high pressure valves and piping between the low pressure pump suction and the reactor coolant system of either unit. Therefore, this line has not been analyzed further with respect to interfacing system LOCA. A.3.6.2 Indication of Overpressurization or Interfacing LOCA There are two pressure indicators in the control room, one for pump suction and one for pump dischstre. There is a separate pressure sensor on the suction piping which alarms in the control room. It is the low pressure suction piping that is at risk and it is protected by a 1.5" relief valve set at 150 psig. The low pressure piping is bounded by the pump on one end and by closed valves in the two possible suction source lines in the CST (check valve) and the suppression pool (N.C. MOV). There are four sets of four high temperature sensors connected in one-out-of-two-twice logic for monitoring HPCI steam line leaks / breaks. This would alarm to the operator. There is also area radiation monitoring availabe in the HPCI pump room.
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- 26 Notes Att equipnent has the following prefix,1301, j If other prefix is not shown.
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A-74 Table A.3.1 Shutdown Cooling Supply (RHR)
- 1. Numbe'r(oflines- 1
-e
- 2. Line size - 20"
- 3. Valve number - 1001-47* 1001-50*
- 4. Valve location - Outside Inside
- 5. Valve type - MO gate MO gate
- 6. Valve operator - de ac
- 7. Valve normal position - Closed Closed
- 8. Power failure position - Closed Closed
- 9. Isolation signals - A,U,M** A,U,M**
- 10. Normal flow direction - out out
- 11. Surveillance requirement - CI CI
- 12. Pump surveillance requirement - N/A to this mode of operation
- 13. Relief capacity &
RV-44 1.5" @ 150 psig setpoint -
- Interlocked to prevent opening with primary pressure > 100 psig.
**See Table A.3.10.
CI:LLRT and position indication once per operating cycle; stroked at each cold shutdown.
A-75
~., Table A.3.2 Reactor Head Spray (RHR) t
- 1. Numberhflines- 1 .
-F
- 2. Line size - 4"
- 3. Valve number - 1001-64 1001-63* 1001-60*
- 4. Valve location - Inside Inside Outside
- 5. Valve type - Check MO gate MO gate
- 6. Valve operator - ac de
- 7. Valve normal position - Closed Closed Closed
- 8. Power failure position - Closed Closed
- 9. Isolation signals - - ** A,U A,U
- 10. Normal flow direction - In In In
- 11. Surveillance requirement - None CI CI
- 12. Pump surveillance requirement - N/A to this teode of operation
- 13. Relief capacity & RV-59 RV-22A&B RV-166A&B setpoint - 1" @ 408 psig 1" @ 408 psig 1" @ 450 psig
- Interlocked to prevent opening with prieary pressure 1 100 psig.
**See Table A.3.10.
CI:LLRT and position indication once per operating cycle; stroked at each cold shutdown.
A-76 Table A.3.3 LPCI to Reactor (RHR) 5
- 1. 2 Numbe'r{oflines-
-p
- 2. Line size - 16 in.
- 3. Valve number - 1001-68A,B 1001-29A,B* 1001-28A,B
- 4. Valve location - Inside Outside Outside
- 5. Valve type - A0 check MO gate MO globe
- 6. Valve operator - air ac ac 4
1 7. Valve normal
- position - Closed Closed Open
- 8. Power failure position - Closed Open
- 9. Isolation signals - - ** RM,H,Y RM,H,Y i
- 10. Normal flow direction - In In In
- 11. Surveillance
- requirement - R SAA/M0/C SAA/MO
- 12. Pump surveillance requirement - SAA/FRT/PO
- 13. Relief capacity & RV-22A,B RV-59 RV-166A&B setpoint - 1" @ 408 psig 1" @ 408 psig 1" @ 450 psig
- Interlocked to prevent opening with primary pressure 1 375 psig.
. **See Table A.3.10. SAA: Simulated Automatic Actuation - each refueling. FRT: Flow Rate Test - after pump maintenance and every 3 months. PO: Pump operability - once per month. MO: MOV operability - once per month; position indication at refueling. i R: . Stroked at refueling. C: LLRT at refueling.
A-77
;, Table A.3.4 RCIC Injection Line*
- 1. Numberk,of lines -
1 -
- 2. Line size - 6" (pump suction)
- 3. Valve number - 1301-50 1301-49 1301-48
- 4. Valve location - Out Out Out
- 5. Valve type - A0 check MO gate MO gate
- 6. Valve operator - air de de
- 7. Valve normal position - Closed Closed Open
- 8. Power failure position - Closed Open
- 9. Isolation signals -
- 10. Normal flow direction - In In In
- 11. Surveillance requirement - M0 SAA/MO SAA/MO
- 12. Pump surveillance requirement - SAA/FRT/PO
- 13. Relief capacity &
setpoint - 1 0 RCIC pump suction (RV-31) 1" 6 150 psig
*RCIC injection line connects to the feedwater system piping outside the drywell.
In order to have an interfacing systems LOCA the valves in Table A.3.5 must also fail. SAA: Simulated Automatic Actuation - each refueling. FRT: Flow Rate Test - after pump maintenance and every 3 months. PO: Pump operability - once per month. HO: MOV operability - once per month. l
A-78 3 Table A.3.5 Feedwater Connection from RCIC to RPV
- 1. Numberi,of lines - 1 -
- 2. Line size - 18"
- 3. Valve number - 220-58A 220-62A 4 Valve location - Inside Outside
- 5. Valve type - check check
- 6. Valve operator -
- 7. Valve normal position - Closed Closed
- 8. Power failure '
position - ---
- 9. Isolation signals -
'10. Normal flow direction - In In
- 11. Surveillance requirement - C C
- 12. Pump surveillance requirement - N/A N/A
- 13. Relief capacity 4 setpoint - None C: LLRT at refueling.
A-79
'~.
Table A.3.6 Core Spray to Reactor
- 1. 2 Number
-p
{'oflines- .
- 2. Line size - 10" from RPV thru CI valves, then 12" to pump
- 3. Valve number - 1402-9A,B 1402-25A,B 1402-24A,B
- 4. Valve location - Inside Outside Outside
- 5. Valve type - A0 check MO gate MO gate
- 6. Valve operator - air ac ac
- 7. Valve normal position - Closed Closed Open
- 8. Power failure position - --
Closed Open
- 9. Isolation signals -
- RM,Y RM,Y
- 10. Normal flow direction - In In In
- 11. Surveillance
- l -
requirement - R SAA/MO SAA/MO
- 12. Pump surveillance j requirement - SAA/FRT/PO
- 13. Relief capacity & RV-28A,B setpoint - 2" @ 475 psig SAA: Simulated Automatic Actuation - each refueling.
FRT: Flow Rate Test - af ter pump maintenance and every 3 months. PO: Pump operability - once per month. MO: MOV operability - once per month. R: Stroke at refueling. See table A.3.10.
-- - - - . . - . - - . , - - - , - - - - - - - , - , . , - - - - - - , - - , _ --- - - - - - - - - - - - , - - - - - . - , ~ - - -
,-.n.- -
A-80
~, Table A.3.7 HPCI Injection Line*
l t ' i
- 1. Numbe'rkoflines- 1 -
-P
- 2. Line size - 14" (pump discharge), 1.c (pump suction)
- 3. Valve number - 2301-7 2301-8 2301-9
- 4. Valve location - Out out Out i 5. Valve type - A0 check MO gate MO gate
- 6. Valve operator - air de de l
l 7. Valve normal position - Closed Closed Open
- 8. Power failure position - -
Closed Open
- 9. Isolation signals - --- HPCI turbine trip j 10. Normal flow direction - In In In
- 11. Surveillance requirement - S SAA/MO SAA/MO I 12. Pump surveillance l requirement - SAA/FRT/PO
- 13. Relief capacity & '
setpoint - 1 @ HPCI pump suction (RV-23) 1.5" @ 150 psig
*HPCI injection line connects to the feedwater system piping outside the drywell.
i i in order to have an interfacing system LOCA the valves in Table A.3.8 must also fail. SAA: Simulated Automatic Actuation - each refueling. l FRT: Flow Rate Test - after pump maintenance and every 3 months. l PO: Pump operability - once per month. MO: MOV operability - once per month. S: Stroke every cold shutdown (need not be more frequent than once per 90 days). 1 s
A-81
-, Table A.3.8 Feedwater Connection from HPCI to RPV
- 1. Numbe'r{of lines - 1 .
- 2. Line size - 18"
- 3. Valve number - 220-58B 220-62B
- 4. Valve location - Inside Outside 5.
Valve type - check check
- 6. Valve operator -
- 7. Valve normal position - Closed Closed
- 8. Power failure position - --- ---
- 9. Isolation signals -
- 10. Normal flow direction - In In
- 11. Surveillance requirement - C C
- 12. Pump surveillance requirement - N/A N/A
- 13. Relief capacity &
setpoint - None C: LLRT at refueling.
i NM _*,,L9_ Screening of Lines Penetrating Courah: ent for Interfacing Lines at Quad Cities PRINCIPAL PENETRATIONS OF PRIMARY CONTAINMENT AND ASSOCIATED ISOLATION VALVES Drywell I
"'~
location * * ' " ' Valve Part Penetration Valve Ecf to Normal Isolation Puwer Power Number Line Isolated Number Type Class 2 Drywell Status Signal to Close to Open 223-1 A, D,C,D 11ain steam line X-7 AO Globe A Inside Open D, C, D, P air & air & ac, de '- spring 203-2 A, D,C,D Main steam line X-7 AO Globe A Outside Open D,C,D,P air & air & ac, de spring 223-I Main steam line drain X-8 MO Gate A Inside Closed B, C, D, P se ac 220-2 Main steam line drain X-8 MO We A Outside Closed B, C, D, P de de 220-59 A,B From reactor feedwater X-9 Check A-X Outside Open 'Rev, flow Process - 220-58 A,D From reactor feedwater X-9 Chcck A-X Inside Open Rev. flow Process - 220-44 Reactor water sampic X-41 SO Valve A Inside Closed D,C,D, P Spring ac 220-45 Reactor water sample X-41 SO Valve A Outside Closed D, C, D, P Spring ac 301-95 Control rod hydraulic ret X ?? Check A-X Y Outside Opens Rev. flow Process - oc - 301-98 Control rod hydraulic ret . X-3G Check Inside rod Rev. flow A-X 0",y Process - 50-120 Control rod drive exhaust None SO Valve A-X Outside ment & None - Spring ac SG-121 Control rod drive exhaust None SO Valve A-X Outside ,eoal see Spring ac S0-122 Control rod drive iniet None SO Valve A-X Outside other Normal Spring ac SO-123 Control rod drive inlet times - Ner.c SC Valve A-X Outside Status Spring ac - 1001-47 RilR Reactor shutdown cooling supply X-12 MO Gate A ' Outside Closed A,U, @ de de 1001-50 RIIR Reactor shutdown cooling supply X-12 MO Gate A Inside Closed A, U, @ ac ac 1001-37 A D RIIR to suppression spray header X-211 MO Globe B-X Outside Closed G,S ac ac 1001-26 A, B ItllR - containment spray X-39 MO Gate D-X Outside Closed G,S ac ac 1001-23 A.D RIIR - containment spray X-39 MO Gate B-X Outside Closed G,S ac ac 1001-63 RIllt - reactor head spray X-17 MO Gate A Inside Closed A,U ac ac 1001-00 Rillt - reactor head spray X-17 M O Cate A Outside Closed A,U de de I001-36 A, B ItllR test line to suppression pool X-210 MO Globe D-X Outside Closed G ac ac - 1001-34 A, D ItIIR - suppression pool test return X-211 MO Gate D-X Outside Closed G ac ac 1001-29 A D RIIR - LPCI to reactor X-13 MO Gate A-X Outside Closed HM,R,@ ac ac 1001-28 A, D RIIR - LPCI to reactor X-13 MO Globe A-X Outside Open RM, II, @ ac ac ,,
Tgb b A.3.9_(Continued) I Drywell Imcation Valve Part Penetration Valve ' 2 Refto Normal Isolation Power Pow b I* Number Line Isolated Number Type Class Drywell Status Signal to Close to Open 0 1001-68 A, D ~ . EllR - LPCI to reactor X-13 AO Check A-X Inside Closed Note (3) (3)
- E 1001-7 A, D,C,D RIIR pump suction X-204 110 Gate D-X Outside Open Rh!, @ ac ac E 1001-20 RIIR to radwaste -
110 Gate A Outside Closed A,U ac ac E 1001-21 RIIR to radwaste - 110 Cate A .Outside Closed A,U ' de de B 1101-16 Standby liquid control X-110 Check A-X Outside Closed Rev. flow Process - B 1101-15 Standby liquid control X-Il0 Check A-X Inside Closed Rev. flow Process - Q 131-2 Reactor water c!canup supply X-14 MO Gate A Inside Open A,W,Y,@ ac ac Rht G 1201-5 Reactor water cleanup supply X-14 MO Gate A Outside Open A,W,Y,@ de de RM > 0 1201-80 Reactor water cleanup ret X-15 MO Globe A Outside Open A,W,Y,@ ac ac h RM G 1201-81 Reactor water cleanup ret X-15 Check A-X Inside Open Rev. flow Process - Q 1301-16 RCIC - turbine steam supply X-10 MO Gate A-X Inside Open K, @ ac ac , B 1301-17 RCIC - turbine steam supply X-10 MO Gate A-X Outside Open K, @ de de E 1301-11 RCIC - turbine exhaust X-212 Check B-X , Outside Closed Rev. flow Process fwd flow E 1301-64 RCIC - turbine extaust X-212 Stop Check D-X Outside Closed Rev. flow Process fwd flow E 1301-55 RCIC - vacuum pump discharge to X-222 Stop Check D-X Outside Closed Rev. flow Process fwd flow suppression clamber E 1301-40 RCIC - vacuum pump disclarge to X-222 Check D-X Outs!de Closed Rev. flow - - suppression chamber 3 1301-12, 13 RCIC - steam line drain None AO Globe D-X Outside Open D Spring alr/dc } 1301-31, 35 RCIC - steam line drain None AO Globe B-X Outside Open D Spring air /dc 3 1301-25 RCIC - pump suction from X-227 MO Gate D-X Outside Closed RM de de suppression clamber 1 1301-27 RCIC - pump suction from X-227 Check D-X Outside Closed Rev. flow - - suppression clamber
Tchla_A.3.9_(Continued) Drywell I Location * '" Velve Part Penetration Valve Retto Normal Isolation Power PoweY " T"' Number Line Isolated Number Type Class2 Drywell Status Signal to Close to Open 1400-24 A, B Core spray to reactor X-16 h10 Gate A-X Outside Open Rh!, @ ac ac 1400-25 A, D Core spray to reactor X-16 110 Gate A-X Outside Closed Rh!, @ ac ac 1400-9 A,D Core spray to reactor X-IG AO Check A-X Inside Closed Note (3) (3) 1400-4 A, D Core spray test to suppression pool X-210 hlO Globe D Outside Closed G ac ac 1400-3 A, D Core spray pamp suction X-204 lilO Gate D-X Outside Open Rh!, @ ac ac 2001-3 Drywell equipment drain discharge X-19 A O Cate D Outside Open A, F Spring air /ac 2001-4 Drywell equipment drain discharge X-13 AO Gate B Outside Open A, F Sprir.g air /ac 2001-15 Drywell floor drain discharge X-18 AO Gate D Outside Open A, F Spring air /ae 2001-16 Drywell floor drain discharge X-18 AO Gate D Outside Open A, F Spring air /ac Y on 2301-4 IIPCI - turbine steam X-11 AIO Gate A-X Inside Open L, Rh!,@ ac ac
- 2301-5 IllTI- turbine steam X-11 h10 Gate A-X Outside Open L,Rht,@ de de 2301-20I 2301-30f 2301-64f IIPCI - steam line drains None AO Globe A-X Outside Open G Spring alr/dc .
2301-65 l 2301-45 IIPCI- turbine exhaust X-220 Check D-X Outside Closed Rev. flow Process twd flow 2301-74 IIPCI - turbine exhaust X-220 Stop Check D-X Outside Closed Rev. flow Process fwd flow 2301-3G IIPCI pump suction from suppression X-225 AfD Gate D-X Outside Closed Rh!, L de de cla mber 23 1-39 11PCI pump suction from suppression X'-225 Check D-X Outside - Rev. flow Process fwd flow clumber 23 1-71 11PCI turbine exhaust drain X-221 Stop Check D-X Outside Closed Rev. flow Process fwd flow 2301-34 IIPCI turbine exhaust drain X-221 Check B-X Outside Rev. flow Process fwd flow 700-73G Traversing in-core probe X-35 SquibShear A-X Outside Open Rh! de de 700-733 Traversing in-core probe X-35 SO Dall A-X Outside Closed AF ac ac
__ Table _A.3.9_(Cont;inued) I Drywell location Valve Part Penetration Valve R f to Normal Isolation Power Power ,,m. Number Line Isolated Number 2 .,. Type Class Drywell Status Signal to Close to Open
- D 220-18 A\ l Instrument sensing line X-29, -50 Iland Globe A-X Outside Open Iland lland D 220-12 A) \ Steam flow measurement X-29, -50 Flow Check A-X Outside Open Rev. flow Irand Spring '-
] 1001-38 A Instrument sensing drywell pressure X-32 Iland Globe D-X Outside Open Rev. flow Iland lland l'
By AE Service air to drywell X-21 Check B Outside Closed Rev. flow Spring - f ByAE Service air to drywell X-21 AO Globe D Outside Closed RK1 Spring air HyAE Instrument air to drywell X-22 Check B Outside Open . Rev. flow Spring - Dy AE Instrument air to drywell X-22 AO Globe D Outside Open RM Spring . air
~ HyAE Rcator building close cooling X-23 Check C-X Outside Open Rev. flow Process -
water in DyAE Reactor building close cooling X-24 MO Gate C-X Outside Open RM ac ac water out Dy AE Service water in X-20 Check C-X Outside - Rev. flow Process 1601-20 A, B p Vacuum breaker sec. cont. to X-205 Check D Outside - Suppres- - :n suppression sion pool "" pressure 1601-33 Vacuum breaker suppression X-202 Vac Bkr B Inside - - Drywell - to drywell pressu.e suppression 1601-32 Vacuum breaker suppression X-202 VacBkr B - - Drywell - - to drywell chamber pressure 1601-21, -22 Drywell purge inlet ~ X-26 AO Duiterfly B Outside Closed FA Spring air /ac IG01-23 Drywell main exhaust X-25 AODutterfly B-X Outside Closed FA Spring air /ac ( 1001-G1 Suppression chamber exhaust X-203 AO Gate B-X Outside Closed FA Spring alr/ac valve bypass 1001-5G Suppression ciomber purge inlet X-205 AO Butterfly B-X Outside Closed FA Spring alr/ac 1601-60 Suppression chamber main exhaust X-203 AO Butterfly D-X Outside Closed FA Spring alr/ac 1601-24 M.iin primary containment exhaust X-202 AO Dutterfly B-X Outside Closed FA Spring air /ac X-25 1
A-86 Table Ae3.10 - Key to the Isolation Signal Codes in the Tables f Signal ( . Code ** Description A Desctor low water level"A* . sersai and sleet teolation valves except mata steam lines. 3 Ilesctor low water level"S" . Anattate RCIC and elese main steam line toelatten valves.
@ Valtt opens en signal"B".
C II6sh rad 6atten . mala steam !!ae. D Line break faste steams line (steam line high space temperature er excess steam flow). l F High drywe6l pressure . elese drywe!! aimeopmer6e centrol and secondary containment testat6en valves, scram reacter. . O lteacter low water level *C" or haga drywe!! pressure e laattate core sprayg RHR. and upci s,steme.
@ Valve opens en signal"G". Signal"L" everrideo signal @.
N Line break in recirculation leep . close corresponding InitR.LPCI leep valves and open ealves in oppossie leep. .
@ Line treak in cleanup systema e high space temperature! alarna onlyg no aute elesere.
K Line bresk in RCIC system steam line to tuttime (high steams llae space temperature er eteese steans flow or low steami Itae pressure) . overrides signal 3. L Line bresh in HpC! system steam line to tertine (high steam 16ne space temperature or entess steams flow or low steam line pressure).
@ Line treak in ItHR shutdown and head coo!6ag (high space temperature; alarm only;
- as aute closure).
P the mean steam 16ne pressure at talet to ma6e turbine (run ;aede only).
$ taw drywell pressure e elese contanament spray and suppression eseling valves.
T taw reacter pressure permissive to spea core spray and RIIR.LPCI valves. U High reactor pressure
- close AllR shutdown cooling valves and head coetang valves.
@ Valve opens on resacident signate "G* and "T" Signal"H* everrides signal @.
W High temperature al outlet of cleanup system ionregenerative heat exchanger. Y 8tandby liquid control system actuated. 2 High radiation. process rad monitor, reactor building ventilation ethaust plenum. RM Reinote manual switch f rom romrol room.
- Encircled letters appear with a bar over them in some of the tables.
A-87 Table A.3.10 (Continued) Notes for Tablest i I. t : 1 Basic penetration numbers are shown. Suffix letters that follow the basic number are given on the appropriate piping and instrumentation diagram. 2 C1sss A valves are on process !!nes that communicate directly with the reactor vessel ana penetrate the containment. 4 Class B valves are on process lines that do not directly communicate with the reactor vesset. but free space. penetrate the primary containment and communicate with the containment Class C valves are on process lines that penetrate the primary containment but do not oirectly communicate with the reactor vessel or with the primary containment free space and are not on !!nes that communicate with the environs. A fourth class of valves are exceotions to the above definitions. Their class desig-nations are tollowed by an "X" suffix; for example. A-X. These valves either can be opened af ter a containment signal or are opened automatically on certain contatn-ment signals to permit the operation of the control rods. the standby liquid control system and the various core and containment cooling systems. Minimum closing rates for each isolation valve shall be: . Class A valves shall be closed prior to the start of uncoverine of fuel caused by otowdown from that line. The main steam isolation valves closing' time shall be adjustable between 3 and 10 seconds during specified flow and temperature. ; Class B and C valves closure times shall be selec'ted to limit radicadtivity release tront containment to below permissible limits in the event et a loss-of-coolant accident blowdown within the primary containment. (The closure rates given are as required for contalament isolation only--system - operational requirements may be more restrictive.) 3 Testable check valves are designed for remote opening rfth approximately zero catterential pressure across the valve seat. The valves will close on reverse flow even though the test switches may be callin;; for open. The valves will open when
' pump pressure exceeds reactor pressure even though the test switch may be calling '
for close. 6 s 4* 4 4 g k th r T k
B-1 APPENDIX B Description of Incidents Involving Failure of Pressure Isolation Valves at BWRs Inthfhappendix,detaileddescriptionsoftheincidentsidentifiedin : Section 3 are provided. The valve arrangements for the interfacing lines involved are shown in Figures B.1 through B.11. B.1 Vermont Yankee (LER 77-04) On December 12, 1975, with the plant at 99% power, monthly operability surveillance testing was being conducted on Loop "A" LPCI injection valve V-10-25A. Initially, injection valve V-10-25A failed to respond to an open signal from its remote control switch. To determine if the motor-operated valve failure was caused by excessive differential pressure across the valve disk or a specific mechanical or electrical malfunction, plant personnel first manually cracked open V-10-25A. Then the valve was successfully cycled fully open and ,
' closed. During this time, unknown to the plant personnel, testable isolation .
check valve V-10-46 downstream of the injection valve was not seating properly, and the supposedly closed motor-operated valve (V-10-27A) upstream of the injection valve was partially open. With a partially open flow path between the RCS and RHR system unknowingly established, RCS water at operating pressure and temperature flowed into the low pressure LPCI Loop "A" system piping, pressurizing it in excess of its design pressure. High pressure in the line caused a mixture of steam and water to be discharged from each of the three RHR system relief valves and the RRR heat exchanger tube sheet-to-shell flange area. The gasket in the tube sheet-to-shell flange area began leaking as a result of the elevated pressure conditions. The exact cause for the testable isolation check valve not seating properly was not reported at the time of the event in 1975. The upstream injection valve (V-10-27A) had been closed from the control room prior to opening V-10-25A as
]
part of the surveillance test sequence, but failed to fully shut. The partial ' opening of the motor-operated valve was not known by plant personnel at the time of the event due to a false closed position indication. The exact causes for the faulty position indication also were not reported at the time of the event.
1 . A-2 - l Following successful pressure and operability testing of the subsystems involved l in the overpressurization event, the subsystems were declared operable. \ a? s t-t B.2 Coopec5 Station (LER 77-04) , On January 21, 1977, with the plant operating at 97% power, plant personnel < vere in the process of performing high pressure coolant injection (HPCI) system turbine trip and initiation logic surveillance testing. When the injection-valve was opened, as required by the surveillance test, feedwater flowed backwards through the injection line, pressurizing the HPCI system close to operating pressure. It was not reported whether the low pressure suction piping of the HPCI system also was pressurized in excess of its design pressure during the event. The licensee determined that the HPCI testable check valve (AO-18), i
. downstream of the injection valve, had been stuck open during the test allowing feedwater to backflow into the system when the injection valve was cycled open. l The extent of flow through the open check valve was not known.
The testable isolation check valve was disassembled following shutdown of the reactor about two weeks later and was found to be blocked open by a 14-1/2" long sample probe which had wedged under the edge of the valve disk. This prevented the check valve from fully closing. It was determined that the broken probe had come from a sample point on a 24" feedwater line upstream of the HPCI injection line junction. The length of time that the check valve had been stuck open was not determined. B.3 LaSalle-1 (LER 82-115) On October 5,1982, with the plant operating at 20% power, quarterly surveillance testing on the high pressure core spray system (HPCS) was being conducted. The testable isolation check valve 1E22-F005 and its associated bypass valve 1E22-F354 failed to indicate completely closed after they were opened fro the test. Both the testable isolation check valve and its bypass valve are situated on the HPCS injection line inside primary containment. The
B-3 HPCS system was declared inoperable. The motor-operated HPCS injection valve was closed and deactivated.
.t .
During* the surveillance test, the' check valve bypass valve 1E22-F354 was - first opened to equalize the pressure on both sides of the testable check valve disk. The testable check valve was then tested open by operating a remote hand switch. This hand switch energized a solenoid valve to allow instrument air to be supplied to one side of the piston cylinder of the air operator of the testable check valve, causing the piston cylinder.to move a rack and gear ( assembly against spring tension. The rack and gear assembly movement rotated the actuator rod which lifted the valve disk off its seat. When the hand switch was returned to its closed position, the solenoid valve was de-energized, cutting off instrument air supply to the piston cylinder. This should have allowed the spring (tension) to ret 6rn the rack and gear assembly to.its normal position. This, in turn, should have rotated the actuator rod back to its original positien, allowing the valve disk to reclose by its~own weight and differential pressure.
) . - The failure of testable check valve 1E22-F005 to reclose was investigated by the licensee and was determined to have been caused by (1) dried lubricant on the actuator piston cylinder; (2) insufficient preload on the actuator spring assembly; and (3) the stuck open testable check valve bypass valve 1E22-F354.
Together, these causes prevented the piston cylinder of the check valve air operator from returning to its fully retracted position. B.4 LaSalle-1 (LER 83-0661 On June 17, 1983, with the plant at 48% power and quarterly operating surveillance of the HPCS system in progress, HPCS testable isolation check valve 1E22-F005 and its associated bypass valve 1E22-F354 failed to indicate closed after being tested open. The HPCS system was declared inoperable and was isolated by deactivating the normally closed motor-operated HPCS injection valve. The licensee determined that the failure of the testable isolation check valve to reclose was caused by (1) the stuck open bypass valve 1E22-F354 which
B-4 4 prevented a pressure differential from developing across the valve disk of the testable check valve, and (2) possibly thermal binding of the check valve disk.
.t With respsdt to the latter cause, the licensee indicated that the Anchor Darling ! t check valvemand bypass' valve have a tendency if tested hot to remain partially .I open after being cycled. The failure of the bypass valve to reclose was traced to insufficient return spring tension in the bypass valve. While shutting down the plant, both the bypass valve and the testable check valve closed without:any assistance as reactor pressure and temperature decreased. Subsequent to an analysis of the event, the licensee submitted a request to conduct surveillance testing of testable check valve 1E22-E005 only during cold shutdown.
4
. B.5 LaSalle-1 (LER 83-105) l On September 14, 1983, the plant staff was in the process of performing;a routine RHR system relay logic surveillanc'e test with the plant in cold shutdown. At the time of the test, the "B" RHR loop was lined up with both
'drywell spray valves 1E12-F016B and IE12-F-17B open, the suppres'sion pool spray
- valve IE12-F027B open, the test return to the suppression pool valve IE12-F024B 4
open, and the "C" RHR loop injection valve 1E12-F042C open. Unaware that the LPCI loop "B" testable isolation check valve 1E12-F041B was stuck open, the plant staff opened (as required by the test precheck) the "B" RHR loop injection valve 1E12-F042B. When the injection valve was opened a rapid decrease in
- reactor vessel water level was observed. Water level dropped quickly from +50" l to 0" causing a Group VI primary containment isolation at.+12.5". The operator quickly secured the valve line-up stopping the water level decrease. Most of 4
the water lost from the reactor vessel went to the suppression pool. while some went to the drywell. The cause of the draindown was determined to be the stuck open testable l isolation check valve 1E12-F041B on the loop "B" LPCI injection line. Thus,. when the injection valve was opened during the test, an open flow path between the reactor vessel and the suppression pool and drywell was established which ) allowed backflow of reactor water into the drywell and torus. The isolation. ) check valve also provides the first isolation barrier between the high-pressure I RCS and the low pressure RHR system when the plant is at power. I i
B-5 The testabl=. isolation check valve was stuck open due to two causes. First, it was held open by its attached air operator as a result of a misalignme of the interfacing gears between the check valve and the air operator. - The misalignment resulted from maintenance errors on the air operator that were made earlier in the outage. During the maintenance, a score mark on the spline shaft of the check valve was used instead of a timing mark for aligning the gears. This resulted in the air operator holding the check valve disk in the open position and inhibiting disk movement in the closed direction during the draindown. Additionally, the packing gland on the check valve shaft was found to be too tight, inhibiting free movement of the valve disk. I B.6 Pilgrim (LER 83-48) On September 29, 1983, during HPCI system logic testing while the plant was at 98% power, the low pressure suction piping of the HPCI system was overpressurized to near operating reactor pressure and temperature.. The event occurred when two HPCI pump discharge motor-operated valves were simultaneously opened as a result of personnel errors. The errors consisted of conducting more than one surveillance test at the same time and not ensuring that test prerequisites and initial test conditions for all steps in the test procedures were met. The overpressurization occurred, when the pump discharge valves were opened, because the testable isolation check valve downstream of the discharge valves was also partially stuck open at the time. The overpressurization of the suction piping (which is designed for 150 psi) ruptured the gland seal condenser gasket on the HPCI turbine. This in turn caused a mixture of water and steam to spray from the condenser onto a limit switch. The water spray resulted in a 250-V de battery ground and a large amount of water on the HPCI room floor. Smoke detector alarms also were set off by the vapors from the heated paint on the low pressure piping. A high suction pressure alarm and a lube oil high temperature alarm were also actuated. The exact cause for the testable check valve being partially open was not determined. There was some evidence that a rusted linkage between the valve steam and the attached air operator had contributed to the testable check valve being partially open. In the short term, the licensee repaired the linkage and returned the valve to its correct position. The licensee decided to replace the
B-6 check valve with a new design as a long term solution. To prevent a recurrence of the perspnnel errors, instructions for verbal communications were to be implemente at the plant. B.7 Hatch-2 (LER 83-112) On October 28, 1983, with the plant in cold shutdown, the testable isolation check valve on a 24" LPCI injection line of the RHR system was found open and could not be closed. It was determined that the valve was being held open by its attached air operator. The licensee's investigation revealed that the air supply line to the air operator had been connected backwards in a prior maintenance on the valve on June 7, 1983. The resultant pneumatic pressure reversal caused the air operator to hold the check valve open even though the check valve was not being tested. The mispositioned check valve was not detected for a four-month period during which the plant operated at close to full power. The failure to detect the mispositioned valve was attributed to a reversal of the electrical leads for the valve position indicator following the
' June 7, 1983 maintenance. This had apparently been done by piant personnel in the belief that the valve was actually closed. Inadequate post maintenance testing also contributed to the error not being detected.
During the four-month period when the testable check valve was held open, the normally closed motor-operated LPCI injection valve upstream of the check valve remained closed. As a result, inadvertent overpressurization of the LPCI/RHR system did not occur during this period. An immediate corrective action taken by the licensee following discovery of the maintenance error was to correctly reconnect the air supply lines to the check valve air operator. This placed the check valve in its correct position. The licensee also counseled plant maintenance personnel on the importance of performing equipment maintenance correctly. For the long-term, the licensee was to consider adopting an alternative testing method for the check valve which would not require the use of the air operator.
~
5 B-7 B.8 Susquehanna 2 (LER 84-006) I ;f OnMay{21,1984, a dual indication was received on testable check valve HV-2F050B9dhd its associated bypass valve HV-2F122B. LPCI injection valve " (Anchor Darling, horizontally mounted gate valve) HV-2F015B was closed and
- deenergized. Later that day, RHR throttle valve HV-2F017B was closed and
-2F015B was cycled in an attempt to seal -2F050B; when -2F017B was reopened the -
'B' RHR primary side HX pressure was observed increasing and -2F017B was closed. Since -2F015B was deenergized, the 'B' LPCI was inoperable and an LCO
! was entered.
j On May 24, 1984, an LLRT showed that leakage was occurring through -2F015B ! and the leakage was the source of pressurization in the HX. Valve -2F017B was
, deenergized to ensure separation between the HP and LP portions of the 'B' RHR.
l Loop 'B' of the LPCI remained inoperable and the reactor shutdown was commenced , on May 28 in accordance with Tech Spec. 4 ! Shutdown proceeded normally until it was observed that the No. I turbine bypass valve would not close below the 18% open position. Shutdown was halted i and control rods in Group 5 were pulled sequentially to maintain reactor pressure with the No. I turbine bypass valve controller at a position slightly greater than 18%. It was determined that the best means for accomplishing { j shutdown would be through an RPS manual scram. The plant control operator i tripped the 'B' reactor FW pump and closed all inboard MSIVs at -700 psig. Upon disassembly and inspection of LPCI valve -2F015B it was found that the valve's disc would not center on its seat due to the dimensions of the disc guide bearing surface. This resulted in the valve's disc sitting low in the
- body. Due to machining tolerance during afg the disc would not seat in the same l location each time it was stroked. To stop leakage through the valve, its seat was lapped and its lower disc guide bearing surface was built up 1/4".
The valve was reassembled and an LLRT and hydro were completed on June 7 and 8, a respectively. 1 } The cause of the dual indication on the testable check valve's bypass,
- -2F122B, was attributable to a loose diaphragm plate connector that resulted in i
. . . . - . ~ - . . _ . . _ . , . _ . . _ _ , . _ _ _ . _ . - - _ _ ~ . - . . , , . - - _ . _ _ . . . _ , . . . _ . . . . - . _ . - _ _ _ . . . . , _ - _ _ _ . _ - _ _ .
c B-8 improper contact'with the limit switches on the bypass valve. The plate connector and its set screws were tightened and the operator was l reconnectd .' , B.9 Browns Ferry-1 (LER 84-032) On August 14, 1984, while at 100% power and during the performance lof a six-month surveillance test of the core spray system logic, the normally closed motor-operated core spray system injection valve was inadvertently opened. When the valve opened, reactor coolant at operating pressure and temperature backflowed into the low pressure core spray system pressurizing the system piping close to full reactor pressure. The backflow also heated portions of the system piping to about 400 F. A mixture of hot water and steam sprayed from the pump seal of pump "A" of Train 1 of the core spray system. A fire alarm was set off by the plant vapors from the hot piping. Thirteen workers were contaminated by the sprayed water while responding to the fire alarm. The overpressurization, which lasted about 13 minutes, was terminated when plant personnel reclosed the injection valve. An investigation by the licensee following the event determined that the normally closed testable isolation check valve, downstream of the injection valve, had also been open during the event. With the check valve open, a flow 7 path between the high-pressure RCS and low pressure core spray system piping was created when the injection valve was inadvertently opened. The cause for the open testable check valve was traced to a pneumatic pressure reversal in the air actuator. The reversal was caused by an earlier maintenance error in installing a plunger with reversed air ports in the air actuator pilot solenoid valve.. A
- review of plant maintenance records indicated that the valve likely had been held open since December,1983. The valve misposition was not detected for the ensuing eight-month period because the valve position indications were altered following the maintenance such that the valve misposition was not evident.
A review was also conducted to determine the cause for the inadvertent injection valve ^ opening during the surveillance test. The test procedures specified that the valve motor operator circuit breaker should be opened so that the valve would have no motive power and would remain closed during the logic J f
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B-9 test. It was determined, however, that the licensed operator assigned to perform thip step had failed to open the breaker. Thus, when test signal was applied ddr ng the logic test, the injection valve opened. B.10 San Onofre On November 20, 1985, at 11:30 p.m., the plant was operating at reduced power of 250 MWe due to a tube leak in the main condenser, when ac alarm sounded in the control room indicating a ground was detected by the ground detector on 4160-V bus IC. Such a condition does not interrupt power to the equipment and thus the operation of the plant equipment was routine. While the plant personnel were troubleshooting this problem, a station blackout occurred. First, at 4:51, power to bus 2C was lost. Twenty seconds later, pcwer to bus 1C was lost. The operators manually tripped the reactor. The reactor trip initiated a turbine trip. Power from the cwitchyard was restored b r minutes later. Feedwater pump FWS-G-3A receives its power from bus IC, ar.e feedwater pump WS-G-3B receives its power from bus 10. When power to bus 2C was ' interrupted, pump FWS-G-3A stopped. Its discharge check valve FWS-438 failed open. With feedwater pump FWS-G-3B still running, backflow of feedwater through pump FWS-G-3A occurred. The piping and components upstream the feedwater pump are not designed for high pressure. The tubes of the flash evaporator condenser was overpressurized and ruptured, causing the shell to rupture. The main feedwater regulation check valves FWS-345, 346, and 398, also failed open. This resulted in the blowdown of the steam generators through the ruptured flash evaporator, after feedwater pump FWS-G-3B stopped on loss of power. The discharge check valve FWS-439 of feed water pump FWS-C-3B also failed open. This resulted in backflow through the pump after it lost its power. As a result of low steam generator level, the turbine driven auxiliary feedwater pump was started automatically. The warmup cycle takes about three minutes. During this time, no feedwater was available. This resulted in voiding of the feedwater piping between the feedwater regulation valves and the steam generators. After the warmup cycle was completed, the pump started to deliver approximately 130 gpm AFW flow to the main feedwater line. The reverse flow in the main feedwater line carried AFW to the condensate system.
..t b , ,
B-10 Af ter elect ric power das restored, the operators, following emergency procedure after reactor trip, isolated the main feedwater lines by closing MOV-20,21f22,FCV-456,457,and458. This terminated the blowdown of the t I steam genesators, and started refilling the voided feedwater line. The motor driven auxiliary feedwater pump started automatically after power was restored. At about 5:07 a.m., a water hammer in the feedwater line to steam generator B occurred. This resulted in displacement of the feedwater piping, damage to many pipe hangers and snubbers, an 80" crack with 30% through the wall on the 1" thick feedwater piping, and leakage of the bypass check valve FWS-379. The leaking check valve FWS-379 was identified during a containment entry at 8:00 a.m. and isolation was achieved at 10:45 a.m. by closing the manual valves in the B steam generator feedwater line and the bypass line. Throughout the incident, except the duration of station blackout, the
- primary coolant inventory was maintained by' controlling charging and let down.
~ Reactor coolant pumps A and C were operable to enhance heat removal through the steam generators.
The following describes the failures of the' check valves: Valve Description As-Found FWS-345 MFW Reg Check SG A Disc separated from hinge arm, disc stud broken (threaded portion). FWS-346 MFW Reg Check SG B Disc separated from hinge arm, disc stud deformed. FWS-398 MFW Red Check SG C Disc nut loose. Dise partially open. Disc Caught inside of seat ring. FWS-438 FWP Discharge Check Dise nut loose. Dise partially open. Disc caught on inside of seat ring. FWS-439 FWP Discharge Check Dise nut loose. Disc partially open. Antirotation lug lodged under hinge arm.
B-11 B.11 Pilgrim ; On Fe 'uary 12, 1986, with the plant at 100% power, periodic RHR high system presture alarms (greater than 400 psig) occurred and RHR system piping between valve 28B and the RHR pumps have been noticed to be warm. It was believed that this is due to back leakage of primary coolant through the inboard check valve and the 1001-28B injection valve. The design pressure alarms have been noted but not logged for several weeks. Operators vented the piping after. each alarm. Several actions were taken to stop the leakage. The MOV 288 was manually tightened. The torque switch on the valve was found set too low for complete closure. It was replaced and reset. The normally open MOV-29B was closed. The plant operttion was continued. On April 11, 1986 with the reactor at 94% power, leakage through MOVs 28B and 29B occurred and resulted in high pressure alarm in the LPCI line. The first alarm was at 1415. Operators bled off the line to the normal 125 psig pressure. Pressure increased to the 400 psig alarm in 2 hours. The plant was shutdown in 24 hours. 4
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D-1 Appendix D: Discussions on Data Used in Quantification of the Frequency of Interfacing LOCA
- t This .-dppendix discusses the sources of some failure data listed in Table :
4.1, and provides the derivation for the rest of the failure rate data listed in Table 4.1. Table 4.1 is reproduced in Table D.1. Each failure event in the table is discussed as follows.
- 1. MOV Rupture - This failure represents catastrophic failure of MOV such that the valve is widely open. A LER search was performed to identify failures of injection valves in LPCI, LPCS, HPCI/HPCS, and RCIC systems in BWRs.
Five events were found, in which valve disc was separated from the stem. The number of injection valves for each plant was determined by the information provided in the event V inspection report for region I reactors l and the FSARs for other plants. The number of reactor years for each plant was obtained from the grey book dated February 1986. The total number of BWR injection valve years is the summation of the products of the number of injection valves and the number of reactor years. It is estimated to be 4173 valve years. Therefore, the failure rate is calculated as the number of failures divided by the number of valve years, i.e., 1.2x10-3 per year.
- 2. MOV Transfer Open - This failure mode represents failures in which a MOV is opened inadvertently due to human errors during test or maintenance, or due to failures of hardware such as valve control circuits and power supplies.
The failure rate for this failure mode is taken from Seabrook PSA,2 where generic data was used to estimate this failure rate.
- 3. MOV Failure to Close While Indicating Closed - This failure mode represents failures in which a MOV fails to close fully after being opened, such that the valve is leaking while the indication in the control room shows the valve is closed. The failure data for this failure modo is also taken from Seabrook PSA. This failure mode results in limited leakage through the valve. If an interfacing LOCA occurs with a MOV failed in this mode, the LOCA is limited to a small LOCA.
D-2
- 4. MOV Inadvertently Opened - This failure mode represents operator error during logic system functional test at Peach Bottom, such that the injection valve.iis. opened inadvertently. While performing the test, the operator is suppose l1 to energize a relay to inhibit the open signal to the inject' ion -
valve. The procedure requires the operator to initial this step after performing it. If this step is skipped, the injection valve will open when the actuation signal is inserted. The human error probability for this event is taken from the handbook for human reliability analysis.3 The probability of error of omission in use of written procedures, with clockoff provisions and long list of items, was used. 5-9. Air Operated Check Valve Failure Modes - The nine incidents of failures of air operated check valves identified in Section 3 are used to estimate the failure rates of five failure modes. Similar to the analysis done for MOV rupture, the number of air operated check valves at each BWR is estimated using the region I event "V" report and FSARs, and the number of reactor years is estimated based on the grey book. The number of valve years is , estimated to be 1361. Therefore, the failure rate for each failure mode is equal to the number of events divided by 1361. For example, the frequency that the air operated check valve is held open due to reversed' air supply is calculated based on two events, Browns Ferry-1 and Hatch, in 1361 years, i.e., 1.47x10-3 per year. Similarly, the frequency for the failure mode that the check valve is held open by foreign material is estimated using the Cooper incident. The frequency, that the check valve is opened due to rusted linkage between the valve stem and the air operator, is estimated using the Pilgrim incidert. The frequency, that the valve is held open due to misalignment of gears between the check valve and its operator, is estimated based on the incident at 1.aSalle-1 on September 14, 1983. The four remaining failures identified in Section 3 represent leaks through the check valves. They are used to estimate the frequency of check valvo leakage.
- 10. Check Valve Rupture - This represents catastrophic failure of the check valve. The failure rate is taken from the PSA procedures Guide," where the failure rate was estimated using experts' opinion in a reliability data workshop.
D-3
- 11. Check Valve Leak - This failure mode applies to the pump discharge check valve in the high pressure core spray system of Nine Mile Point-2. The failure -rate is assumed to be the same as that of the testable check valve.
12-15. Squares of Failure Rates - Some isolation valve arrangements involve two valves of the same type in series, e.g., RHR shutdown cooling suction and vessel head spray at Nine Mile Point-2. Therefore, two valves may fail due to the same failure mode, e.g., both RHR suction valves may fail due to rupture. The expression for the failure of both valves involves the square of the failure rate. Due to the uncertainties in the failure rates, the point values are considered the means of the probability distributions for them. The mean of the square of a random variable is related to the mean of the random variable by the following: E(X2 ) = (EX)2 + variance (X) where E(X2 ) is the mean of the square of X, EX is the mean of X, and variance (X) is the variance of X. In order to use this equation, the variance or the probability distribution of X io needed. How to calculate each of the squares of the failure rates is explained in the following: MOV Rupture - The probability distribution for catastrophic failure of MOV, given in the PSA Procedure Guide," is used as a prior distribution. A Bayes update using the evidence of five events in 4173 years is performed. The mean of the square is calculated using the discretized probability distribution for the posterior distribution. HOV Leak - The probability distribution for this failure made is given in Seabrook PSA.2 The parameters for the lognormal distribution are calculated to be u = -9.42$ and a = 0.808 The corresponding variance is 1.05x10-8, A0V Leak - The probability distribution for minor internal leakage of check valves, given in PSA Procedures Guide," was used as the prior distribution. A Dayes updating was performed using the evidence of four events in 1361 years to obtain a posterior distribution. The mean of the square was
l D-4 t calculated using the discretized probability distribution for the posterior distribution. l I' t ' e " A0V Ruaged Linkage - The same procedure as that for A0V leak was used except that the evidence was one event in 1361 years. 1 References l 1. "Special Inspections Regarding Potential Intersystem 0/erpressurization of - ( Emergency Core Cooling Systems (Event V Inspections)," Memo from Thomas E. Hurley, Regional Administrator, Region I, to James M. Taylor, Director, Office of Inspection and Enforcement, USNRC, September 1985.
- 2. Pickard, Lowe and Carrick, Inc., "Seabrook Station Probabilistic Safety Assessment," Prepared for Public Service Company of New Hampshire and Yankee Atomic Electric Company, PLG-0300, December 1983.
- 3. A. D. Swain and H. E. Cuttman, " Handbook of Human Reliability Analysis with ;
Emphasis on Nuclear Power Plant Applications," NUREG/CR-1278, August 1983.
- 4. R. A. Bari et al., "Probabilistic Safety Analysis Procedures Guide,"
NUREC/CR-2815, July 1985. l i l l l i l l
D-5 Table D.1 Some Data Used in the Quantification of the Frequency of Intersystem LOCAs Failure Eve'tp Failure Data Sources
- 1. HOV Rupture 1.20x10-3(/ry) See Appendix D
- 2. H0V Transfer Open 8.10x10-4(/ry) Seabrook PRA
- 3. H0V Failure to Close While Indicating Closed '
1.07x10-4(/ demand) Serbrook PRA
- 4. HOV Inadvertently Opened 3x10-3(/ demand) Har.dbook of Iluman Reliability Analysis
- 5. A0V Opened Due to Roversed Air Supply ,
1.47x10-3(/ry) See Appendie D
- 6. A0V Opened Due to Foreign Material 7.35x10-"(/ry) See Appendix D
- 7. A0V Opened Due to Rusted Linkage 7.35x10-4(/ry) See Appendix D
- 8. A0V Opened Due to Misalignment of Cears 7.35x10-4(/ry) See Appendix D
- 9. A0V Leak 2.94x10-3(/ry) See Appendix D
- 10. Check Valve Rupture 8.80x10-"(/ry) PSA Procedures Guide
- 11. Check Valve Leak 2.94x10-3(/ry) Same as A0V Leak 12.Lamda Rupture Square (MOV) 2.06x10-6(/ry2 ) EX2 =(EX)2 War. j 13.Lamda Leak Square 2.20x10-8(/ry2) 2 EX =(EX) 2+ var.
14.Lamda Leak Square (A0V) 1.09x10-5(/ry2) 2 EX =(EX) 2+ var. 15.Lamda Rust Square 2.13x10-6(/ry2 ) 2 EX =(EX) 2+ var. j
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