IR 05000324/1990036
| ML20059M648 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 09/17/1990 |
| From: | Belisle G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059M642 | List: |
| References | |
| 50-324-90-36, 50-325-90-36, NUDOCS 9010050142 | |
| Download: ML20059M648 (42) | |
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UNIT E~) ST ATES !
'/ km atruq'o NUCLEAR REGULATORY COMMISSION i 8' * ,d REGION ll j h 101 MARIETTA STREET, * * ATLANT A GEORGI A 30323
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Report Nos.: 50-325/90-36 and 50-324/90-36 Licensee: Carolina Power and Light Company P. O. Box 1551 Raleigh, NC 27602 Docket Nos.: 50-325 and 50-324 License Nos.: DPR-71 and DPR-62 . Facility Name: Brunswick 1 and 2 Inspection Conducted: August 21-25, 1990
, Team Members: E. Girard, Reactor Inspector, Region II N. Le, Brunswick Project Manager, NRR W. Levis, Brunswick Resident Inspector S. Sparks, Reactor Inspector, Region II Team Leader:
G. Belisle, Chier X-%kS
"N W/7//0 Ghts / Signed Test Programs Section Division of Reactor Safety I
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9010050142 900917 PDR ADOCK 05000324 G PNV
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TABLE OF CONTENTS c
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Page ; I. Introduction - Formation and Initiation of AIT.................. 1
! Background................................................. 1 i Formation of AIT........................................... 1 i AIT Charter - Initiation of Inspection..................... l' ; Persons Contacted..........................................
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2 Ac ro nyms a nd I n i ti al i sm s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . 2
I Description of Events........................................... 3 Overview of Event for Brunswick Unit 2...................... 3
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r Initial Conditions - Event Description. . . . . . . . . . . . . . . . . 3 ! Detailed Sequence of Events...........................- 3 , II Equipment Status, failures / Malfunctions and Anomalies........... 10- Safety Relief Va1ves....................................... 10 ' Excessive Cooldown/Heatup..................................- 12
' HPCI Turbins Stop Va1ve.................................... 14 RCIC Trip and Throttle Va1ve............................... 15 Startup Level Control Va1ve................................ 16
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' RHR Torus Suction Isolation Va1ves......................... 19' Recirculation Bypass Va1ve........................'......... 20 i Main Steam Isolation Va1ves....-............................ 20 i Condensate Booster Pump Discharge Va1ve.................... 21 j
l I Operator / Operational Failures / Malfunctions and Anomalies....... 22
; Alarm Recognition.......................................... 22
! Communications............................................. 23 MSIV 0peration............................................ 23 Reactor Vessel Level Contro1............................... 24 HPCI/RCIC Operation........................................ 24 , Notification /Reportability.................................- 25
; Other Issues............................................. ...... ,26 i t Simulator................................... Eo * QA Review................................... ..............- 26
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V Findings of Fact From AIT....................................... 27 ; r
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< VI Conclusions..................................................... 28 VII Exit Interview with Lfeensee Management..... ................... . 29 ' APPENDICES Appendix 1 Persons Contacted .c Appendix 2 Acronyms and Initialisms FIGURES Figure 1 SRV and MSL Locatio Figure 2 . Target Rock SRV-Assembly Figure 3 Annunciator Penel 2-A-4 Figure 4 Annunciator Panel 2-A-5 Figure 5 2MST-PCIS24M Test Summary Sheet figure 6 HPC1/RCIC Cycles
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:l I. INTRODUCTION - FORMATION AND INITIATION OF AIT ackground . [
Brunswick Units 1 and 2 are GE boiling water reactors IV with Mark I containment The units are located 20 miles south of Wilmington, N.C. at the mouth of the Cape -Fear River in Brunswick County, Unit 2 went critical in March 1975 and was commercially operationa~1 in November'1975. Unit 1 went' critical October-1976 and commercial operations begin in March 197 On Monday, August 20,1990, at 01:51 the licensee notified the NRC Headquarters duty officer af the following event:- l A reactor scram and ESF actuations occurred at 21:54 - on August 19, 1990, after the MSIVs. closed on a Group 1 isolation,. < and three SRVs opened automatically but there is a question 1 on their opening- setpoints.' The licensee was performing a maintenanca surveillance test, involving a trip and calibration of the low condenser vacuum Group 1 setpoint. This is thought to - be the cause of a Group 1 isolation (MSIV closure), but has not been positively ' identified at this time. ~ The reactor-scrammed and all. rods iully inserted into the cor The licensee's investigation ,into the event . revealed that the reactor scram was caused by an I&C techn.cian violating procedural . controls while performing 2MST-PCIS24 During the ensuing plant ! transient, five SRVs did not fully. N ction when reactor system
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pressure exceeded their setpoints, te h?IC trip and throttle valve breaker' tripped on thermal overloaa, and other problems were experienced as discussed in this report. Another reactor. scram had-previously occurred on August 16, 1990,. and some similar problems occurred as in the August 19, '1990,. reactor scram. These are also discussed in this repor Formation of AIT
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On the. morning jof Tuesdty, August 21, 1990, the Regional Administrator, after further briefing by the regional and resident staff and consultation with senior NRC management, directed the formation of an AIT from Region II personnel already onsite and the NRR Licensing- Project Manager and to be headed by the Section Chief of the Region II Test Programs Sectio AIT Charter - Initiation of Inspection The Charter for the AIT was prepared on August 21, 1990. Region II members for the AIT were already onsite performing other inspection activitie The NRR (Licensing Project Manager) representative j , joined the AIT. The special ir:spection commenced with an Entrance
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i Meeting and. briefing of licensee management at 09:20 on August 21', 199 The Charter for the AIT specified that the following tasks be completed: Develop and validate a detailed sequence of events-associated with the Unit 2 reactor trip of August 19, 1990,- ' Identify- any human factors / procedural deficiencies related to the event,
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3.- Evaluate plant' systems' performance as it relates to the: event and identify all equipment, failure . Determine the cause (if possible) of the equipment failures and ' evaluate their significance with respect to radiologi-cal consequences, system performance, safety significance,. and proximity to safety limits as defined in the Technical a Specifications. (Included in the evaluation should be any- ) related or possible contributing equipment failuresLwhich were experienced during the August 16, 1990 Unit 2 reactor trip). Evaluate personnel (Operations and I&C) involvement /a;tions during the associated surveillance test and subsequent to the reactor tri . Evaluate the.cause and effects of the excessive cooldown rates experienced - during the Unit 2 reactor : trips of August 16 and 19, 199 < Evaluate the. licensee's plans / corrective actions to assure equipment operability in Unit 2, as.well as in Unit . Evaluate the licensee's communication of this event to the - NRC, and determine if appropriate notification was made for all reportable occurrences, Provide necessary updates to the preliminary notification on this even . Prepare a special inspection report documenting the results of -the above activities within 30 days of the start of the inspectio D. Persons Contacted I l See Appendix 1 E. Acronyms tad Initialisms
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II. Description of Event , n.- Overview of Event for Brunswick Unit 2 i Initial' Conditions - Event Description On.the evening of August 19,1990, Unit 2 was operating at 100 _ percent reactor power. At approximately 21:00 I&C technicians were given permission by the SCO to commence performing main-tenance surveillance test 2MST-PCIS24M, PCIS High Condenser Pressure Trip. Unit Channel Calibration, Rev. 4. . This test is required to be per'ormed every.31 day The purpose of the tes is to inject a simulated signal into a trip unit, verify the setpoint, and confirm that the logic responds correctl During the test all four channels are. trip tested individuall This MST is performed by I&C te'chnician This test may be performed by one I&C technicial except -for certain critical steps that require independent verification by another -I&C . technicia However, established , work : practices dictate that two I&C technicians perform the test.in its entirety. Testing had been successfully completed .on Channels Al and Bl. Testing was 1 performed on Channel A2; however, the' trip signal was not reset Testing- commenced-on Channel B2 and when the trip signal .was initiated, a full Group 1 isolation signal;was created.. Group 1 . isolation shuts the MSIVs and a scram signa 111s create'd on all ' four RPS channels. Dur.ing the ensuing transient, two MSIVs closed in -less than three seconds, which is .less than allowable - by TS, four SRVs opened _ automatically, on'e SRV partially opened, and various equipment malfunctions .were identified. The licensee's.SIIT post trip investigation identified that only one-I&C technician was performing 2MST-PCIS24M which is cont rary-to the sites established work practice The technician ' performing the test falsely signed procedural-s teps (7. 5.15, 7. 5. 36, 7. 5. 37, 7. 5. 38, .7. 5. 39, 7. 5. 58, 7. 5. 59, l and 7.5.63) when in- fact they had not been performed. The second I&C technician, who was not present- during the MST performance, was called to. the Control Room immediately after the reactor scram. He then falsely signed MST independent - verification procedural steps (7.5.58 and 7.5.59) at the request of the I&C technician performing the tes ' Detailed Sequence of Events Note: In the following licensee's SOE, .all items shown are referenced to the Process Computer, i.e. , three seconds have been subtracted from the ERFIS time l
~ 21:00 Unit 2 SCO granted permission to perform 2MST-PCIS24 l l
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21:37:25 - Testing is -performed on Channel Al 'by a single.- 1 I&C . technicia Second . I&C ' technician who' was i designated; to assist with the test, _ is in' shop - assisting another technician with a recorder
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repai :39:20 The trip signal for Channel Al is rese ~ 21:44:01- Testing is performed _on Channel B .l 21:45:23 The trip signal _ for Channel B1 is rese :49:3 Testing is performed on Channel A This' channel' is not reset as required by the procedure. Seven-steps of the procedure, two of which. require independent - verification: are not performed.: The-independent ' verification: would' have detected the - l failure to . reset. Channel- A2. - The technician : 4 believes the J trip ~ has _ been reset and _ proceeds - with the testing of Channel B ~ 21: 52 C0 questions I&C technician about half Group 1 isolation that is ' sealed in (does not .specify which + channel is sealed in). I&C technician responds that he is a;out-to cause half Group 1; ' isolation and was-proceeding to the Control Room . to inform the' CO (channel. not specified). I&C technician . assumes that' trip Lis from the B2 -
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channel h is presently! testing, and informs 00' j that his half trip was probably caused byta spike , when he'was. dialing in a test signal._ He informs the C0 that -he is continuing with the test and will give him a half' tri ' 21:54:48 Testing is performed on Channel B When the-trip setpoint is . exceeded, a full Grou isolation signal is create The MSIVs start closing. A scram signal. is created on all four RPS channels. Pod insertion i begin :54:50 The closure of the MSIVs increases reactor J pressure and creates a void collapse. All fours I RPS channels detect a low level -(Low Level; 1) and then all four : channels detect the high reactor pressure created by the valves closin The transient low reactor level creates isolation > commands for' Groups 2 and 6-(Low Level 1).
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The pressure transient also creates a suffi-ciently large disturbance to create the Group 1 ) isolction command in the Al and B1 logic. The probable cause of the trip,in these channels is ; from the high steam flow signal. The very high l sensitivity D-P instrument is triggered by the ! pressure variations in the steam line during the l closure of the MSIV :54:50/52' All 8 MSIVs are closed. Two MSIVs (B21-F022A and F0228) close in less than three secord :54:52 Decreasing reactor level creates an ARI signal I and generates an ATWS signal to trip the RR pump The.RR pumps tri :54:53 Reactor level continues to drop due to void-collapse. -Low Level 2 is~ reached. LA Group 3 isolation command is generated and an auto start signal is generated for both HPCI and RCIC, P At Low Level 2, a start command is generated for . SBGT and an -isolation signal ;is- generated for Reactor Building Ventilatio ' 21:55:05 Following E0P-1, Flow Path 3, the C0 removes the mode switch from RUN and places it in SHUTDOW The main generator trips,. in turn- creating a turbine tri All four TSV.and all four TCVFC signals are received in RP RCIC is at speed, the injection valve-(E51-F013) - opens and vessel injection begin :55:06/7 Transient level is recovered above L'e vel 1 (16 inches). All 4 low reactor level channels rese :55:08 The HPCI stop valve opens and- the turbine accelerates. Since level has returned above the Level 2 setpoint, the injection valve will no receive a command to open. HPCI will run on minimum flow until secure j Because the reactor is isolated, pressure
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21:55:08/12 increases. - At a pressure peak of about 1133 psig, SRVs open automatically. According to'the acoustic monitors, valves (B21-F013 0, F, and L) l open for 3.2 to 4 second From the tailpipe ;
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temperature readings,:F013E also auto opene l
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6 j 21:55:36 Reactor high ~ 1evel (Level 8) turbine trip is received, both feedpurap turbines receive a trip-signa :55:42/43 HPCI and RCIC turbines automatically tri The RCIC injection valve goes close :56:25 Since the condenser has been lost as a heat sink, the C0 manually opens' SRV B21-F013B ' to lower pressur The valve is held open for a little more than a minute. Pressure goes below the scram setpoint of 1045-psig; therefore, all four of the high reactor pressure scram. signals rese :57:36 -SRV B21-F013B closes. . Reactor pressure is-about , 910 psi i I 21: 5B: 58 SRV B21-F013F . is lifted manually by the C0 to maintain pressure below the scram poin :59:41 SRV B21-F013F closes. . Pressure is about 900 s psi :00 HPCI is started manually, and is placed in the Pressure Control mod :04 RHR Loop A is started in torus coolin :11 Groups 1, 2, 3 and 6 isolation logic.is rese :13 ' Reactor level drops below Level 1. All 4 low reactor level channels : trip as well as the logic-for Groups 2 & :14 RHR Loop B is placed in' torus' coolin ' The outboard MSIVs are opene :16 Outboard steam line . drain valve B21-F019 is opene :17 Inboard steamline drain valve B21-F016 is opene :16 RCIC is started manually and injects. The rate of reactor level decrease is slowed but RCIC ' cannot supply sufficient inventory to account for steam load being drawn off by HPCI.
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22:24 Group 1_(Channel A2) trips due to a true low condenser vacuum. Steam' is not available to drive SJAE :25 HPCI secured' from Pressure Control and used in r the Injection mode,. to fill the vesse Level recovered to above Level :26/27 Group 1 -(Channel. Al and B1) trip on . l ow . condenser vacuum and a full Group 1 isolation command is receive The outboard MSIVs and the inboard steam line drain valve (B21-F016) go closed.- The outboard-drain valve remains ' open . because the B2 or ~ D channel is.still in test but is not tripped.' t 22:27 HPCI is returned'to Pressure Control, 22:29 RCIC secured manuall :34 HPCI is tripped due to high leve ~ 22:40/42 Valves G31-F001- and F004 are opened' to pressurize the RWCU piping and establish a-reject pat :44 HPCI is restored to normal standby alignmen :47 The logic for Groups 1 (A1, A2, B1), 2 L(A & B) and 6 (A & B) are rese :48 The outb'oard MSIVs ' (F028A-D)' and the two steam _ line drain valves (F016 and F019) are opene :04 Started -motor vacuum pump to restore condenser
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vacuu :07 RCIC started in Pressure Control,-' but is not ! able to maintain pressure because RCIC is not a big enough steam loa :08:41 RPS Channel. A2'is tripped for about a min _ute as reactor pressure reaches = the reactor high pressure trip setpoin A half scram is presen :09:25 HPCI is manually started and placed in = the Pressure Control mode. The turbine stop valve opens, closes, and re-opens.
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23:09:44 The A2 high pressure signal clear :09:47 The A channel half scram is r., se :11 RCIC-secure :17:13/52 A second reactor scram signal .is generate Cause is reactor low -level.- Channel A2' and. B2 - were the' f.irst -.to be tripped but all four ; channels ,did trip. Also received a full trip of
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both Group 2 and.6 isolation logic :18 Manually started RCIC', and began an Injection,- l can maintain level, but level is' not bein ) increase :23 HPCI is transferred from Pressure Control to - Injection and Rx vessel level is returned to the high end of the ban , A Group 1 (Channel A1) tr_ip is receive <
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Drobable cause is the 40 percent steam line flow signal. The half isolation is promptly reset and the inboard MSIVs are opened to restore the ' normal heat sin m Reset of Group 2 and 3 during the step'abov ! 23:25 HPCI is manually secured from vessel injectio : 2B RFP is rese :26 Reactor scram is rese :27 RCIC is tripped, trying to avoid Level 8 tri High reactor level (Level 8) trip is receive :50 Reset and rolled 2B RFP but could :not feed the , vessel because the SULCV would not open i sufficientl The ' control ..'_roem does not have
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position . indication on the valv From local observation it appears the valve was responding but not full strokin August 20, 1990
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00:00 SIIT team begins reactor scram investigatio :03:52 Channel B2 detects a low reactor water leve .
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J scram -of- the evenin The other two sub-channels do not have an opportunity to trip, i Group 28 and 6B isolation commands are receive :05 HPCI is started manually, injects, water level is returned to normal band and HPCI secure i Again the stop valve opens, closes and re-opens i on the starting transien ' 00:06 Throttle' open valve FW-V118 and attempted to control level by _ controlling RFP speed with the motor speed change :23 Level _ 8 turbine trip when ' feedwater system _ over-feeds the vesse :27:29 Group 3A11solatien comman :27:32 Group 3B isolation comman Delta Flow is. th probable cause as this is' the only isolation that_ stems from a single instrumentation sourc :30 CO reset Groups: 28, 6B, and both divisions of Group RWCU valve F001 and: F004 are = opened to restore a reject pat :31 Condensate booster pump 28 manually .secur'e I Water level continues' to increase due to apparent V118 leakag ' i L 00:40 Condensate . booster- pump: 2A manually secured to i prevent water level from reaching the steam lines,
~ 02:00 The RCIC trip and throttle valve-(V8) cannot be reset. The thermals ' on the MOV are found i tripped. RCIC cannot = be restored to normal ;
standby align:aen LCO A2-90-1621.
l SIIT team concludes reactor: scram was caused by . (- ' procedures not being followe'd and independent verification not performe :17 Condensate booster pump 2A started for vessel fee Cannot open the pump: discharge valv Later determined the .overcurrent protection on the pump discha.ge valve-had trippe ! ..
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02:20 Condensate booster pump 2B started for vessel fee Pump 2A secure The- SVLC .is placed in AUTO to control level- .( operating the SULC i End of Event III. Equipment Status,. Failures / Malfunctions, and. Anomalies r Safety Relief Valves Each Unit contains 11.SRVs = associated with reactor pressure vessel overpressure protection. These:are located- on the four. steam lines-between the ' pressure- vessel and the first main steam isolation valv Figure 1 provides a schematic of SRV; and MSL locatio t The SRVs are manufactured by Target Rock Corporation, and are two stage pilot-operated valves consisting of two principle assemblies: a pilot stage assembly and the main-stag (See Figure 2).
' Following a reactor- scram on August- 19 -1990, .a reactor peak ! pressure of 1133 psig was reached upon-MSIV closure.- A review of ; ERFIS data indicated that SRVs D, E, F, and L lifted automatically, and SRVs B and F were later manually opene SRVs.C. H. K; and G < did not lif t when reactor pressure exceeded their setpoints, and SRV i A did not fully lif The acoustic monitor on SRV . E did not- ! function. In addition, SRV E and F tailpipe temperature traces -{ increased at a slower rate than expected. :The closing order for the ; MSLs was determined to be B, A,: 0, and C. The following additional ! SRV summary information was obtained: Design 'As-Left Pilot MSL Setpoint Setpoint Event Sea SRV Location (psig) (psig)- Position- Material l B21-F013A A 1105 1114 Partial open Stellite (new) B21-F013B A 1125 1126 Open manua Ste111te B21-F013C B 1105 1111 Closed Ste111te B21-F013D B 1115 1120 Opened PH13-8MO B21-F013E B 1115 1126 Opened -Stellite s B21-F013F C 1105 1114 Opened Stellite 1 B21-F013G C 1105 1113 Closed PH13-8M0 l 821-F013H D 1115 1123 Closed Stellite (new)- B21-F013J l D 1125 1131 Closed Stellite.(new) i B21-F013K C 1115 1125 Closed Stellite 1 821-F013L B 1125 1126 Opened Stellite (new) , l
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A review of the ERFIS plots also revealed that SRVs D, E, L, and F i lifted approximately 0. 5, 1. 0, 1. 5, and 1. 5 - seconds , respectively, -
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E af ter the reactor pressure peaked at 1133 psi SRV A started to H j open. at 3.0 seconds after peak pressur SRVs D, E, : and L 'are - located on MSL B, which isolated first. The licensee concluded that j since three of the four SRVs on MSL B opened first,- reactor pressure , was already decreasing, and thus SRV A did not fully ope , t The AIT informed the licensee on August 21, 1990, that the 11 Unit 2 SRVs were quarantined in accordance with the guidance contained in NUREG-1303, Incident Investigation Manual, dated February.1988. .The purpose of the quarantine was to minimize the potential for the SRVs ,
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to be manipulated such that important information concerning their performance during the event could be obtained. In accordance with NUREG-1303, the licensee developed a detailed troubleshooting action plan for systematic inspection and troubleshooting . the SRVs to-identify the probable causes for failure to- lif t at the required i setpoin , Past scrams were reviewed to determine if SRV actuation patterns revealed a predominance of SRVs opening on one MSL. - Three such scrams were found, .two on Unit 1 (dated August 19 and September 13., 1986) and one on Unit 2 (dated January 5,1987). In the Unit 1 scrams, only SRVs A, C, D, E,- and L opene No SRVs on MSL D or C opened, even though . these lines contained valves with lower i setpoint In the Unit 2 scram, only SRVs F, G, K, and J opene No SRVs in MSL 8 or A opened. In all three previous scrams, SRVs ' that did not open had setpoints both above and.below the SRVs that did open. The licensee' concluded that the,SRV actuation patterns
.for the August 19 event were not . unusua The licensee also contacted GE with regard to SRV actuation patterns. GE stated that valve openings at different setpoints on' one MSL can be explained by
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the shock wave that travels back toward the reactor vessel af ter the first SRV opens. This shock wave has been known to open other SRVs that are- close to their setpoints. The AIT. reviewed the licensee's SRV as-found setpoint test data performed at Wyle Laboratories after the two Unit 1 scrams and the Unit 2 scram. -Based on this review, the AIT determined that approximately 70 percent of the SRVs which did not lift were greater than the + 1 percent TS limi The AIT informed the licensee on August 24, 1990,- that the quarantine would be removed, and that the pilot valves on the SRVs which did not lif t (SRVs C, K, H G, and A) must be setpoint tested to verify that the SRV lift setpoints were within the TS 3.4.2 limit of
+ 1 percent from their design 'setpoin Testing was performed at l l
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l Wyle ' Laboratories on August 27' through 29, 1990, with the following results: LIFT POINT (PSIG) l Trial SRV C SRV SRV H- SRV G: SRV A 1 1142 1149 1176 1241 1119 ! 2 1103 1130 1121 1115 -1119 3 1115 1123 1117 -1107 1117 4 -1116 1124 1112 1113 1116-Design Pressure Setpoints 1105 1115 1115 1105 1105 These valves were adjusted by Wyle Laboratories in late 1989 and were r installed during the outage which ended in March 1990. Testing results indicated the presence of pilot valve . bonding, since-the first lif t is higher than the subsequent lif ts, except for SRV A which started to open during the event breaking. any bonding. A comparison of the initial lift as-found setpoints with the TS design , setpoint limit revealed an increase for SRVs C, K, H,- G, and A of 3.3, 3.1, 5. 5,12.3, and 1. 3 percent, respectively. -As such, all five SRVs which did not lift during the event exceeded the TS limit of: + 1 percent. - Past industry testing has shown:that the bonding ! process does not seem to be affected by variations.in pilot disc seat materia ' The licensee installed certified replacement pilot valves in the SRVs, (C, K, H G, and A) prior to unit startup. - The acoustic monitor on SRV E was repaired, as well 'as SRV E and F tailpipe temperature problem B. . Excessive Cooldown/Heatup During the August 19,1990,- event, Unit 2 experienced a cooldown of the reactor pressure vessel and recirculation piping. -In addition, , Unit 2 also experienced a plant cooldown and heatup during a reactor scram which occurred August 16, 1990. The AIT obtained the following cooldown and heatup temperature rates from traces for various locations on the reactor vessel and recirculation system piping: August 19 August 16 August 16 Cooldown Cooldown Heatup (F/HR) (F/HR)' (F/HR) RR Pump Suction 115 120~ 170 Reactor bottom head 132 135 Small Reactor Pressure 92 49 Small i , Vessel l l
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13' l TS 3.4.6.1 limits the reactor coolant system maximum heatup an j cooldown rate in any one h9ur- period to less than 100 F/HR.' The 1 basis for this limit is derived from fracture toughness requirements 1 of Appendix G to 10 CFR 50. In aadition, TS 5.7.1 and TS Table 5.7.1-1 provide : the cyciic and thermal transient . limits for the reactor pressure vessel, based on the thermal stress' limits for 1 cyclic operation and fatigue usag l GE SIL No. 430, dated September 27, 1985, provides a summary. o * temperature monitoring measurements L for determining the TS heatup and cooldown rates.. The Slt statet that-the~ proper temperature measurement for determining the reactor pressure. vessel fracture toughness cooldown/heatup rate is thel steam ~ dome saturation temperature, obtained by converting the saturated steam pressure t temperatur Using- the GE SIL recommendations, the above reactor-pressure vessel 'cooldowns indicated that the.TS 3.4.6.1 limit of 100 F/HR was not exceeded (92 F/HR.and 49 F/HR for the_ August 19 and August 16 events, respectively). In addition, using the pressure-temperature curves of TS Table 3.4.6.1-1 for all reactor pressure _, vessel locations, the fracture toughness properties were found to be ' acceptabl As noted in the above table, local areas of .the reactor pressure vessel bottom head and recirculation system piping exceeded 100 F/HR during the August 19 and August 16 -cooldowns and heatup. -The, licensee performed an evaluation to determine the ' effects on ! fracture toughness for the recirculation pump, piping, and- valves, and concluded brittle fracture was not a concern since all of these ; components are fat"icated from stainless stee Stainless steel' material does not experience a temperature where a transition from ductile to brittle behavior occurs. . Thermal. stress limits.for cyclic operation were also determined by the licensee to 'be negligible with - regard to the recirculation pump, piping, and valves. :The localized
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areas of the reactor pressure vessel were also found to be accept-able by the licensee from a brittle fracture standpoin The licensee determined the probable cause of the high cooldown rates on August 19 and August 16 to be a partially clogged RWCU system drain line from the reactor vessel bottom hea The partially clogged RWCU drain line also contributed to the strati-fication problem which prevented the restart of the recirculation ; pump During both cooldowns, both recirculation pumps trippe Before the recirculation pumps could be restarted, .the temperature differential from the steam dome to the bottc.n head drain exceeded the TS 3.4.1.3 limit of 145 F. This TS prevents starting an idle l recirculation loop until the temperature differential is less than 145"F to protect the reactor vessel and CRD housing stub welds from thermal cyclin Because the recirculation pumps could not b restarted, thermal stratification occurred in- the reactor vessel bottom head due to the accumulation of cooler CRD water which could not be drained through the RWCU system drain line. The AIT l l l l
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determined the licensee's operating procedure forithe recirculation system does not- contain adequate provisions when both recirculation pumps trip;and cannot be restarte The licensee attempted to; unclog' the RWCU -system drain line during the ' last Unit. 2 outage. A ~ short term improvement' was observed. in ! the drain line temperature; however, the temperature graduall decreased, indicating an - obstruction _ was 'stilli present. Th , licensee was developing-~a preliminary plan to unclog the RWCU system- ' drain line during the next scheduled Unit 2 ' outage. Discussions with- '. plant personnel indicated that the RWCU drain line has been partially.- clogged since initia11 Unit 2 startup. In addition,.the AIT noted that the piping arrangement- for_ the, drain lineuis essentially the same between Unit 1 and Unit. 2, and the Unit 1 drain line' . 2s- no history of cloggin , The AIT also investigated thef cause of- the recirculation piping ' heatup which occurred on August 16,1990. The C0s placed the B Loop RHR system in shutdown. cooling. However, the recirculation pump discharge bypass valve B32-F032B i was ..in the open position, which : permitted reverse flow of the warmer RHR water to the recirculation ! piping and pump suction. An attempt. to close the: F032B valve : failed, as it tripped on thermal overloa After the August 16 event, the licensee made a Temporary Revision, 90-099,. to procedur _ OP-17, Residual Heat Removal System Operating Procedure, Rev. 89,
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which requires the C0 to close the recirculation pump discharge bypass valve prior to placing the RHR system in. shutdown coolin The licensee performed diagnostic testing of the 'F032B valve, and found no abnormal behavior or. settings for _the torque switch, spring pack displacement, or motor current..- The licensee was continuing
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their investigation into _the cause of _the F0328 valve failur ' The AIT also reviewed GP-02, Approach to Criticality and Pressuriza- , tion of the Reactor, Rev. 30, and GP-05, Unit Shutdown, Rev 43, to - determine which temperatures were used to calculate the'heatup and-cooldown rates to satisfy TS 3.4.6.1. These procedures use the A and B recirculation pump suction temperature.s'for this evaluation, as ; under normal conditions when the recirculation pumps are' operating, this measurement approximates reactor ~ pressure' vessel saturation 1 temperature differentials (GE SIL 430).
tion pumps have aeen tripped, this measu However, ement if the recircula-is inaccurat i l
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C. HPCI Turbine Stop Valve HPCI was manually initiated for recovery from the scram on August 16, 3 199 Although it started and quickly provided the desired level, j a subsequent licensee data review revealed undesirable behavior ' during its startup. . The data showed that the HPCI turbine stop valve (2-E41-V8) had opened, closed for a short time, and then reopene Such behavior increases HPCI response time, which the
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15-j licensee's system engineer indicated had already been' at the 1 LTechnical Specification 3.3.3 limit of 30 second In reviewing data from five additional actuations ~ of HPCI (four manual and one '1 automatic) which occurred in recovery from the subsequent August 19, ' o 1990, scram, the licensee initially noted two instances of apparently , similar turbine stop valve opening, closing and then re-openin l Both of these occurred in the last two manual actuation I Later, a more detailed licensee review found that these two j instances were the result of manual actions taken in accordance with , procedural requirements and were not indications of an equipment ' problem. The anomalous performance of the turbine stop valve in the l ' August 16 actuation remains a concern, however. The licensee's HPCI system engineer informed the AIT- that, based on the recommendations- l of vendor _ representatives, -instrumentation would be insttiled! to monitor the valve actuation _ circuit during future operation to aid - in identifying the cause of the behavior. Also, the engineer noted . that Unit 2 HPCI takes significantly longer to respond than' Unit 1 and that the cause would be explore The system engineer stated that Unit 1 HPCI- had not experienced' similar problems and that its actuation time, unlike Unit 2 HPCI,. ; tested significantly less than the 30 second TS limi RCIC Trip and Throttle Valve Isolating the steam supply to the RCIC- turbine is accomplished b actuating the handswitch in the control room, which causes the-
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spring loaded valve '(2E51-V8) stem to disengage from the actuator and ' close. Resetting the 2-E51-V8 valve (opening V8 after--a RCIC turbine _
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trip) requires the C0 to hold the handswitch in the closed position until the _ actuator compresses the spring and . relatches the valve ste A permanently mounted ' caution tagt next to the handswitch instructs ' the C0 to hold the handswitch- in the closed position for ' five seconds after the closed indicator light is received to insure the mechanism is relatche Approximately four hours after the reactor trip on August 19, 1990, ' i a C0 attempted to reset 'the RCIC turbine trip by closing the.V8 valve. The C0 then re-opened the valve, but the mechanism had- not
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i relatched. The AIT discussed this area with the CO, who stated he could not confirm he held the handswitch in the closed position:for five seconds af ter the closed light indicator was received.~ The C0 was then instructed by the shift foreman.to close the V8 valve again and hold the handswitch in the closed position for greater than five.
l second During the next attempt to re-open V8, the valve motor l l tripped on thermal overload. . The thermal overload for the V8 valve . l l was recently resized such that the ' duty cycle of the motor would not i be exceeded. At the time of the RCIC trip and throttle valve (V8) . l
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16: i1 failure, the RCIC system was not needed to control water level, as the CBPs- were being used- in conjunction with the SULCV to maintain
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and control reactor water leve ] Operating procedure OP-16 Reactor Core ' Isolation Cooling System
- Operating Procedure, Rev. 59, provides ' the following general i precautions for DC Limitorque valves
- - l DC ' Limitorque valves are limit'ed to l a duty cycle of three
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starts in five minutes, followed. by a fifty minute cooldown period. Any valve actuation, whether in the . form.of a throttle action, ' a continuous' stroke,'. or an auto-actuated movement, is considered a motor - start.- ' Adherence to _the duty. cycle requirements will minimize DC. valve motor . failure While attempting to relatch the RCIC V8 valve a second time,. the C0 failed to adhere to the general precautions for DC powered Limitorque; valves, and thus the valve tripped on~ thermal overload. In addition, > the AIT noted that. 0P-16 does not. specify the method. used.'to relatch the V8 valve following a RCIC turbine tri E. Startup Level Control. Valve The SULCV, 2-FW-LV-3269, is used to control reactortvessel level during startups and shutdowns as part of the:feedwater level, control i syste The inability of the C0s to use this valve' satisfactorily l following the scram of August 19. 1990, made recovery more. difficul Manual SVLCV controller settings of' up to about 50 percent failed to ; provide perceptible flow to the reactor to maintain acceptable water level. The, C0s were aware of a past history of deficient SULCV' performance and, faced with Its ' apparent failure . to provide flow, for several hours they relied 1nstead on less' easily: controlled _ means of maintaining reactor water level. Eventually, the SULCV was successfully placed in service in its automatic mod The AIT:obtained details of the' use of the. SULCV in the recovery from discussions with the. licensee and review of operator logs. The l AIT found that the first recorded attempt to.use the SULCV following * L the August 19 scram-was just over 2 hours after the scram. Up until i l that time HPCI and RCIC had been manipulated-as the principal means of maintaining ' reactor level. :HPCI and RCIC had been tripped ! several times due to water-level oscillations. The C0s expected !' that SULCV feedwater flow would' avoid further overshooting of the limits and would require less CO attention. The C0s were unable to L obtain sufficient flow from manual SULCV demand settings in both the p initial try and in two further attempts at its us Low and then l high level limits were again exceeded while using various other ! methods to control level. Finally, two and one-half hours'after the l initial attempt to use the SULCV, it was placed in automatic control l- and satisfactorily controlled vessel ieve , , , - - - .
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The history of- this valve's performance deficiencies ' as w examined ' by the AIT through- discussions with the licensee and a review of maintenance history (work requests) since January 1986. Licensee * engineers stated that many of the past problems appeared- to have been due to vibration from valve cavitation and to insufficient-actuator size. In March 1988, the valve and actuator were replaced in a design change intended to eliminate these deficiencies. The ., AIT's review of maintenance work requests found five repairs between , January 1986 and this modification and.four following the modifica- t tion (exclusive of repairs af ter the August 19 scram). The repairs required in the two plus years following the modification. appeared i more significant than - those experienced in the two years before ! replacement, The repairs included a valve failure in the open position due to a loose air nozzle flapper, valve closing in response to reduced reactor level instead oof. opening which was caused by a - defective controller, a defective transmitter found during calibra-tion, and debris in the I/P transducer air nozzle which resulted in inadequate responsivenes Considering that use of the'SULCV is limited to startup and: shutdown of the reactor, it appeared to the AIT that.the. licensee's modifica-tion had not been successful in correcting SULCV operational' deficiencies. The licensee's investigation of ~ the inability of the : C0s to use this : valve in initial' recovery from' the August 19 scram revealed the following contributing factors: ' s
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C0s were not aware-that up to about a 60 percent open controller setting, the current valve design provides about a 1:2 ratio of flow to demand (i.e. , a 20 percent change in. controller open ! demand setting would yield about 10 percent more flow). j
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The SULCV is not frequently used -(limited to startup and l shutdown) and C0s were familiar with its performance mostly from operation on the. simulator. The. simulator does not simulate the actual flow to demand ratio expected for this valve but rather l a 1:1. ratio approximating the action of the SULCV that was i replaced in 1988.
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The licensee's investigation following the August 19 event found [ l that, due to planned setup deviations and an error caused by L apparent drift in an I/P transducer (about B percent each), the valve did not : begin to open in testing until a demand setting of almost 20 percent' The licensee provided the AIT
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a test results that indicated.this factor, in combination with ' the first factor noted above. - resulted in ' a flow of less than 15 percent for a 50 percent controller settin ,
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Contrary to procedural precautions, feedwater valve FV-177 had been opened (and then closed) prior to opening the SIILCV. This l at least partly emptied the downstream line such that initial flow was consumed in refilling the line rather than the' reacto l l l
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There is no flow instrumentation installed for direct measurement of flow provided through the SULCV. It is assessed indirectly as changes in reactor water Llevel are observe Based on the known~ history of SULCV' operational deficiencies, C0s were quick to assume it was malfunctionin t In reviewing records of. previous licensee experience with deficien operation of this valve the AIT found that, as reported in Brunswick ' LER 2-88-019, there had been- a- previous failure of the SULCV to provide adequate feedwater to the reactor while recovering from a scra This occurred November. 16, .1988,: approximately. 8 month after the valve modification in. March 1988. - Prior to attempting toi use the SULCV .for level control in the scram, valve FV-177 had been opened to aid in providing .an output demand. signal of = 30 - 60 percent from the SULCV, as specified by procedure. _ This permitted . the piping downstream from the SULCV to drain to the condenser. The feedwater pump- was then started, ' pressurizing the _ upstream piping and producing an 1100 psig discharge pressure. Controller. manual
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demand settings of up to 100 percent and closure of valve FV-177 failed to produce an increase in vessel. level. Sufficient flow was - finally obtained by opening the bypass valve (V120). The LER offered two possible causes for. the inability to control ~1evel . with the SULC First, the SULCV might not have been-able to open against the differential pressure created' when - the FW pump was started (its design rating was 920 psig). The licensee informed the AIT that this was no longer considered a plausible cause, as- the vendor had since , informed the licensee that the SULCV was capable of opening against a differential pressure of 1200 psig. .The second explanation offered was that the SULCV might have actually opened, but that refilling the large diameter (16-inch, 20-inch, and 30-inch) downstream piping had delayed injection into the vessel 1 causing: the: COs- to. believe the SULCV had- failed. The LER stated that corrective action had been~to t revise the licensee's . procedure to require -leve1 ' control to be > established with SULCV before FV-177 would be opene The LER also indicated that E0P training would be provided to assure this sequence of valve alignment was followe The AIT found that the LER-2-88-019 event- was described in the Brunswick Operator Training Student Study Material, Condensate & i Feedwater, Rev. 6. .This document' indicated that the failure to o provide flow through the SULCV was due to the inability of the valve to open against high differential pressure. Although it did not identi fy the refilling of downstream feedwater: lines (following FV-177 - opening) as a reason why - reactor ' level did not respond to
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demand (stated to have been set at 100 percent), it did state that-the procedure had been changed to open -the SULCV before FV-177 to _ _ _ __...-_r--- . . * * -___
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. . 19 I l prevent drainin' g the downstream piping prior to feeding the vesse , The AIT verified = that precautions were included in the procedures I but found that other statements -in the procedures may have' caused -
' COs to use insuf ficient SULCV settings, as-described-in section IV.0-of this repor The AIT noted that the inability of the licensee to control reactor level with the SULCV, as described in LER 2-88-019, f was identical to that experienced following the August 19 event in most respect In the case of the LER event, the- SULCV apparently :
failed to provide a sufficient response on a 100 percent demand, as compared to the 50 percent used in .the August 19 recovery. It appeared to the AIT that corrective = action stated by- the LER ha been inadequate based on recurring difficulties-in using the SULC ! FV-177 was again opened before the SULCV in ~ the August 19 recovery ,
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despite procedural changes _ intended to preclude thi j As understood by the AIT, the licensee's. corrective actions in response to the SULCV operational deficiencies identified for the- i August 19 scram recovery were as follows:
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Corrected 8 ' percent ;ULCV positioner. setup error and initiated action to preclude recurrence by changing setup procedur Corrected 8, percent I/P transducer error by replacing transducer and calibrating the replacemen Initiated operator training and action to have SULCV in j simulator match action of SULCV installed in plant, i
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Installed operator. aid to provide guidance on SULCV _ operatio RHR Torus Suction Isolation Valves-Two of the loop B torus suction isolation valves, 2-E11-F004B and D, failed on thermal overload in realigning valves for startup following the August 16, 1990, scra These valves are normally keylocked open during operation to assure a path for LPCI. They are closed for 3
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shutdown cooling to isolate the reactor'from the toru i The licensee's engineers stated there was a recognized history of ! thermal overload failures for all of: the Unit 1 and 2 -RHR F004 , valves on thermal overload and it was believed due to thermal ! binding (binding between the valve body and~ disc caused by the valve ! body contracting proportionally greater than the- disc when the- i closed valve cools). Licensee . investigations have been unable to : determine the exact cause. The AIT's review of the licensee's work history since early 1986 identified three thermal trips on the Unit 2-F004B valve and one on the D valv ; JM
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l i As already noted, these loop B - valves are open during normal - operation, the position required for their safety function. Although they are closed for shutdown cooling, no credit is taken in the FSAR' for them to .open to establish a LPCI- flow path and they have no automatic open (or close) Mgi . The licensee's engineer stated t5at corrective action recommended
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for these valves was to crack then, off their seats manually prior to motor operatio ; Recirculation Bypass Valve ! This 4-inch motor. operated double-disk gate valve 'is. normally open , during operation and provides a minimum flow path for recirculation 5 pump startu Following the scram.of August 16, 1990, recirculation bypass valve 2-832-F0328 failed partially open on thermal overloa T_hi s occurred during an' attempt to close the valve- to aid in reducing an
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excessive heatup rate being experienced coming out of - shutdown coolin Subsequent licensee troubleshooting. and diagnostic testing
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failed to identify any _ deficiencies in valve operation. The valve closed satisfactorily as soon as the thermal -trip was rcse The AIT reviewed the maintenance history of this valve _ from 1986: to presen Two instances of operational failure were identified, Lone in 1986 and the other in 1988, In both cases the valve would not i close. The 1986 failure was attributed to out of adjustment limit switch fingers and the 1988 failure to a weak actuator spring _ pac There was no apparent relation - between - these . failures and the -
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current failure. The licensee stated they found no past history of'
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, ! thermal trips for either -this valve or the equivalent Unit 1 valve.
j The most recent maintenance on the valve consisted 'of a packing - l adjustment. Run current was measured following the adjustment and' reportedly indicated no unusual characteristics.- L Inability to close this valve may have ' contributed' to the recirculation piping exceeding heatup rate limits (100 F/HR). ' H. Main Steam Isolation Vaives The Group 1 isolation resulting from the low condenser vacuum trip I signal initiated the automatic _ closure of the MSIVs. The AIT's-review of the ERFIS information indicated that' the order of closure
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21 ! r and closure = times after the Group 1 isolation for the inboard ~.iSIVs
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were as follows:
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Main Steam Line . Valve Number Closure Time (Seconds) B B21-F0228 2. 5 A B21-F022A . D B21-F0220 C B21-F022C 3. 2 TS 3.4.7 requires the closing times for MSIVs be greater than. or equal to 3 seconds, and less than or equal to 5 second The basis ; behind the 3 second' requirement is to preclude overpressurization of the reactor system upon MSIV closure, As noted above, MSIVs B and A j closed in less than 3 second Subsequent to1the initiating event, on August 23, 1990,'the licensee performed PT-25.1, Nuclear- Steam' -Supply System Main Steam and Feedwater Isolation Valve Operability Test, Rev. 18. Results indicated that all full stroke times were satisfactory except for
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B21-F0228, which stroked in 2.51 second The licensee initiated-WR/JO 90-APAll-to adjust ~ the stroke time to within specification In addition, WR/JO 90-APAJ1- was also written to increase the stroke time for B21-F022A, which during the PT-25.1 retest stroked in 3.025 seconds. The licensee stated the' probable -stroke time drift could - be attributed to a nitrogen -leak in the accumulator or a hydraulic - lea I. Condensate Booster Pump Discharge Valve Late in the recovery from' the scram of August 19, 1990, an attempt ! was made to start condensate booster pump-2A to provide feedwater to : ; increase reactor water level. It did not. start due to the failure i ' of its motor operated discharge valve (2-C00-V4) to open. 'The-28- .! pump was started in its plac The- licensee's investigation ' determined that the valve had tripped on overcurrent. Thec2A pump-had been shut down and its discharge valve had been closed 1 hour and 20 minutes earlier. The licensee stated that their investigation indicated the current trip setting on the discharge valve had been"
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set too' low and that this was 'being corrected. There was little or no direct safety significance to the failure of this valve to operate I during event recover There were a number of other systems as well as two additional booster pumps to provide water for level contro l It was indirectly significant, however, as the failure resulted in an ' additional. problem for C0s to resolv . l l
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. -.- 22 i IV. Operator / Operational Failures / Malfunctions and Anomalies i The - AIT reviewed operating logs, normal and emergency operating procedures, SOE printouts from 1.RFIS . and the process computer, ~ ERFIS-
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traces of- critical plant parameters and interviewed operations personnel to determine the adequacy of C0 actions with respect to their involvement , with the . initiating event, recovery actions and communications of event ;
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to the NR ' Alarm Recognition-Prior to the performance of a surveillance test, the I&C technicians ! provide a summary sheet to the -CD This sheet provides a summary-of the test along with expected alarms.and possible affects on plant , operatio The summary sheet for 2MST PCIS24M (see Figure 5), which - i is included as Attachment 7 to the procedure, states -that- the following alarms will be received during the test: : RPS CHAN A TRIP CAB TROUBLE (2-A-4, 5-1)' RPS CHAN B TRIP CAB TROUBLE (2-A-4, 6-1) GRP 1 ISOL LOGIC A/C. TRIPPED (2-A-5, 5-3) GRP 1 ISOL LOGIC B/D TRIPPED (2-A-5, 5-4) As described in the SOE, the I&C technician failed to reset channel A2 prior to proceeding -to test channel 'B2. In this' condition, A tripped and.82 in test, the. following alarms would exist: GRP 1 ISOL LOGIC A/C TRIPPED (2-A-5, 5-3) (indicates half tri3 condition from channel A/C). See Figure RPS CHAN B TRIP CAB TROUBLE (2-A-4, 6-1) (indicates testing of B channel). See Figure 4
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The annunciator procedure for these alarm windows clearly states that a trip of logic A and logic B will result in a full scra Had the C0s acknowledged the alarms ' and referred to the annunciator - , procedure as required by Sections 6.4 of 01-01, Operating Principles - l and Philosophy, Rev. 32, they should have realized that testing on-the B- channel with the A channel tripped was not an expected . I condition and would result -in a reactor trip. Instead, the C0s relied on the MST cover sheet which told them that the alarms were expected to be receive ' l
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> Communications
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As described in- the SOE, the C0s received an unexpected half trip signal from channel A2. The MST requires that the technician inform the C0s prior to initiating a half trip signa When - the CO - questioned the I&C ' technician about the half trip condition, the technician, who was testing channel B2 at the time, assumed that the C0 was referring to the B channel.- He informed the C0 that the trip ' was probably due to a spike when the read out. module for the channel that he was testing was- energized. The. technician'further stated ; that he was ready to continue with the testing and would be' giving ' the CO 'a half trip. The C0 assumed that the half trip would occur i on the channel already tripped. Neither the C0 nor the technician
. specified the channel (A or B) to which they were referring. Th AIT noted that the C0s did not demand a complete explanation of th .
unexpected half trip received.from channel A [
' MSIV Operation t
As part of the scram recov ry, and as specified in the E0Ps,'the C0s were instructed to equalize around and'open the MSIVs- so that the condenser could be re-establishedz as? a heat sink. The- C0 accomplished this task by following the instructions provided on a
"hard card", an operator aid for this evolution. After opening the
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outboard MSIVs and the inboard and outboard drain valves, the CDs l were equalizing pressure around the inboard MSIVs when an actual low condenser vacuum resulted in a Group 1 isolatio [ The MSIVs can be opened with no vacuum or low vacuum conditions provided that the MODE switch is not in RUN and the condenser vacuum ' bypass switch is in BYPASS. .During this evolution, the MODE switch- ' ' was in SHUTDOWN, but- the vacuum bypass' switches had; not been taken-to BYPAS This requirement was not specified on the "hard card" t l that the C0 was following. The AIT did note that this requirement ' l 1s specified in 2-0P-25, Main Steam System Operating Procedure, ' Rev. 31, Section When the C0s opened the MSIVs on the second attempt, the" received a !' one-half Group 1 isolation due to high steam flow above 40 percen Because Unit 2 has 100 percent bypass capability, it .has ' a additional Group 1 isolation signal on high steam flow with the MODE switch not in RUN to prevent' rapid depressurization due toLan EHC L failure. The one-half isolation signal received at this time was caused by steam flow and pressure perturbations following' the , l opening of the first inboard MSI This _ has been a recurring problem as described in LER 2-89-1 ' The operating procedure, OP-25, has been revised .to state that Group 1 isolations' can be expected when opening the MSIVs under these condition '1 '
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. 24 Reactor Vessel Level Control During the scram recovery, two additional RPS trips occurred from , low level (162.5- inches) conditions. The lowest level following the l scram not including the initial level transient caused by the scram itself was 152 inches. The AIT reviewed plant _ conditions at th time of the low level conditions. The level control problems can be primarily attributed to difficulties in opening the MSIVs and i placing the_ SULCV in service. The difficulties in ' opening the MSIVs are described in the previous paragrap SULCV problems are described in more detail itSection III.E of this repor The inability to place the SULCV in service affects level directly as the other injection ' systems had been - secured , in anticipation of the RFPs being.placed in service. The AIT found q that the C0 did not originally place the system in service properl The C0 opened the FV-177 valve. prior to verifying that-the SULCV was open. The C0 was not using a procedure when he placed the SULCV in service. - There is no "hard card" as an operator aid for the C0 to use when performing this evolutio The AIT reviewed procedures that describe placing the SULCV .in-service. GP-02, Approach to Criticality ano Pressurization of the Reactor, Rev. 30;- GP-05, Plant Shutdown,. Rev. 43; and Section of OP-32, Condensate and Feedwater System Operating. Procedure, Re ; all describe how the valve-is to be'placed 'in servic All these procedures contain the necessary. precautions regarding the opening of the FV-177 valve. However, all three also state _ that _ for- optimal control of the SULCV the FV-177 should be opened to obtain enproximately 30-60 percent demand . signal for the SULC Because of tae valve's flow characteristics, this demand signal will result in very little -flow to the vesse Flow to Lthe vessel is further reduced since the FV-177 valve is in a 16-inch line which returns-to the condenser,- Flow'through the SULCV,1which is in an 8-inch line, would be diverted to the condenser in this situatio E. HPCI/RCIC Operation The recent NRC LOR examina*. ion results and the subsequent OPEVAL noted weaknesses in ~ C0 ECCS i,anipulative skills,- especially in the area of HPCI/RCIC operation. During the scram recovery both of these systems were used to control vessel level and pressure. These systems were started and stopped. several times during the event along with changing . modes of system operation. Valves in these systems use DC motors. These motors are limited to a duty cycle of 3 starts in 5 minutes followed by a fifty minute cooldown period. This limitation for these MOVs is stated in both 2-0P-16, Reactor Core Isolation Cooling System, Rev. 59 and 2-0P-19, High Pressure Coolant Injection System Operating Procedure, Rev. 67. Figure 6 lists HPCI
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and RCIC . valves which were cycled during .the event. - Although none exceeded the 3 in 5 minutes followed by a fif ty minute cooldown period criteria, 5 of- the valves exceeded 4: cycles in fifty- five minutes.- None of these valve motors tripped on thermal overload The licensee is currently evaluating these duty cycle limitations- to determine if they are appropriate and they are also investigating methods to reduce cycling the' valves _during operation of the system During the third manual start of the HPCI system the, CO, _following: the instructions on his "hard ' card" for._ starting HPCI, opened the E41-F00.t steam admission valve withL the HPCI auxiliary oil pump . renning. The pump was running because it- had not been secured I foilewing its previous operation. The pump is typically run for a' minimum of 10 minutes following operation to allow for proper cooldown of the syste The problem with. opening the steam jl
admissions valve with the pump running is the . potential for_ a . l turbine overspee _ When the COL came--to the step which required him ;j to start the auxiliary oil pump' he noted- that- it was already running - j and 'immediately tripped .the turbine. He- then proceeded with the i normal startup sequence and successfully ran HPCI. The "hard card"- } 1c deficient- for the case when the auxiliary oil pump is already~ j running as it does not require the C0s to. verify that it is' secured ! prior to beginning the start' sequenc l F. Notification /Reportability !
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During the recovery operations, the STA, while walking the control- .l board, noted. that several. of the SRVs did not lift when reactor ! pressure exceeded their setpoints. This observation was based on I the peak pressure of 1133 psig and that acoustic monitoring indication and ERFIS data showed that SRVs A, C, and G with 1105 j l psig setpoints did not lif SRVs H and cK, with .1115 : psig I setpoints, also did not lif The setpoint tolerance based-on the plant's TS is + 1 percen With this information, the STA i questioned the senior operations person in the control' room about ' declaring an Unusual Event since EAL-1 and -Section 2.1 or PEP- require that an Unusual Event be declared for a ' failure of a SRV to ! open if challenged. The STA was informed that the decision to ! declare an Unusual Event would be deferred until the Technical Support group evaluated the event. and determined if the SRVs should .; have opened. This determination was made the following day and a Unusual Event was- declared and terminated at 17:45 on August 20, j
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1990, due to the licensee's conclusion that SRV C was challenged an i should have opene The initial rmtor scram, which occurred at 21:54 on August 19, k 1990, was reported to NRC under the requirements of 10CFR50.72 *
(b)(2)(ii) at 01:52 on August 20, 199 Following this initial s
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. 26^ event four other four-hour reportable events occurred during the-recovery; The . time of these events and short -descriptions' are as follows: . August 19 ' 22:27 - Group 1' isolation on. low condenser vacuum f 23:17 - RPS trip due-tv low vessel level i
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August 20 ' t 00:04 - RPS trip due to low vessel level 00:27 - Group _3 isolation due to high delta flow
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The first 3 events above were reported on August 21, 1990, at 11:08 as a followup report, to ' the 21:54, August. 19, 1990 event. - The-reportability of the fourth event, Group 3. isolation, wasistilit unde review by the licensee'at the end.of the AIT inspection and no report' had been mad V. Other Issues Simulator The AIT ai ) identified the following concerns where the simulator ! was not representative of actual plant operation or equipment performance: i
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The . simulator models the SULCV position versus flow rate as a ; linear functio The actual operating characteristic is a-non-linear function, and the SULCV is setup such.that it must be opened approximately 20 percent to provide" flo The simulator does not automatically model the tripping of any DC operated valves on: thermal-overload. Thermal overloads were l recently resized for- many HPCI 'and RCIC DC operated valves such 1 that operation is limited to three- starts within five . minutes, l followed by a 50 minute cooldown perio Plant. operation of l these valves greater than three cycles. in five minutes Lis I prevented by tripping the motor on thermal overload. 'However, -l the simulator has the capability such that any. valve can b tripped at the simulator instructor's discretio The'siniulator does not correctly model the relatching operation l of the RCIC trip and throttle valve, 2-E51-V8. Relatt 'he valve stem to the actuator is accomplished by closing i valve, and af ter the closed light is received, the hand ;ch should be held for an additional 5 seconds. The simulator-models the V8 valve relatching when the closed light is received, and thus the handswitch is not required to be held an additional 5 second . .
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- 'The simulator models the SRVs - such that= lif t occurs. at the design setpoint. Actual SRV lif ts could be i 1 percent-(or greater-if an-SRV pilot sticks) from.the. design setpoin .
B.
f QA Review The AIT requested that the QA/QC Manager review recent QA surveil-lances to- determine if problems. such- as identified 'in Section II. A had been previously -identified.- A search for survey findings was , conducted from 198 Ninety-three QA surveys of ' monitoring plant ~ ' activities were reviewed. The AIT al's o' reviewed a list of all surveillance nonconformance- reports ~ and. non significant events (approximately 600) from -1988.. Based on. this review, -site- QA identified three instances where independent verification and/or time and separation requirements were not adhered to. -These examples;. however, do not indicate similar examples as identified in Section II.A. The specific examples - are S-89-01B,- issued February 17, 1989; FR 90-007,. issued February 22, 1990; and S-90-026, issued on April 23, 1990.- VI. FINDINGS OF FACT FROM AIT The initiating'_ event was caused by a single I&C technician who knowingly- ! failed to follow an MST. Following the scr.am, he and another technician falsified documentation to indicate that the MST had. been correctly performed.
' SRVs C, H, G. K, and A did not operate when. primary system pressure . exceeded their setpoints. Subsequent testing verified ~ these SRVs were
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l outside the i I percent TS limi ' Reactor vessel heatup and cooldown rates did not exceed TS limits as originally . suspected, although thes_e rates were high.' The high-cooldown rates were caused by a-partially clogged RWCU drain lin The HPCI turbine stop valve did not ' function correctly during one actuation during the August 16, 1990, scram.
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i Imoroper operation (relatching and multiple cycling) of the RCIC trip and' throttle valve caused the valve motor to trip on thermal' overload.
, ' RCIC operating - procedure does not specify the RCIC trip and throttle L valve relatching method for resetting the turbine-trip.
l The C0s were not able to maintain vessel. level due to improper operation l Ji of the SULC urocedures not followed relative to maintaining FV-177 closed until the SULCV was opened,
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component drift and setup errors, r ! ! 1 . _ - _ _
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inaccu:-te simulator'modeling; and
-- ' lack of CO trainin RHR torus ~ suction valves- tripped 'on thermal overload when aligning the system for startup_ following the August 16, 1990, scra Recirculation bypass valve tripped on thermal overload following .the- 4 August 16.--1990, scra Two MSIVs did not close within TS required time limit !
Condensate booster pump discharge valve' tripped on magnetics (current overload).
C0s did not properly acknowledge and' respond to plant alarms during M51 performanc Communications between the CO and the I&C technician were poo [ Operator _ aid "hard card" did not provide sufficient information for
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properly operating MSIV HPCI operator aid "hard card" does not address HPCI when the auxiliary f
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oil pump is already in servic q
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Unusual Event was not reported conservstively. Four subsequent events j (ESF actuations/ reactor trips) were not reported within the four~ hour reporting perio j s The simulator is not representative of actual plant operation. regarding equipment- for DC Limitorque operated valve'. thermal _- overload protection, .j RCIC trip and throttle valve relatching, SULCV operation,' and SRV lift j setpoin VII. CONCLUSIONS
The AIT found significant personnel issues that caused the initiating ! even An I&C- technician knowingly violated MST procedural steps. 'He i falsified steps in the procedure after the reactor scram indicating
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that the steps were accomplished when they had not been. A second I&C I' technician, who was supposed to be present during the testing,' was no ,, After being called on the public address system and asked to sign .the ' steps requiring independent verification, he did so without verifying -j that the items were complete .
A disciplined operating crew could have prevented this event by recogniz-ing alarms that existed just prior to the event, enforcing communkation
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i standards put in place following NRC LOR examinations, and haviN greater j cognizance of work activities that can effect plant operatio l
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C0 response showed that they were properly focus d on important plant parameters such as pressure and level, and that they could operate HPC1; + and RCIC to control these parameter , Reporting of the events to the NRC was neither conservative nor timel f Obstacles -still exist; however,-that effect the ability of the C0s to i operate the plant. Obstacles evident during these events included bot '
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equipment and trainin Cycle constraints on DC MOVs, RWCU drain line clogging, g deficiencies.-SULCV operation MSIV 40 percent isola binding, and torus suction isolatio,n valve thermal' overloads were, SRV > discrepant equipment conditions that may also be rooted in desig .t Training deficiencies were evident in the simulator modeling problems - noted along with the number of procedures that were inadecuate in themselves or inadequately implemented. The C0s demonstratec that they had the fundamental knowledge and ability to operate various plant systems but advanced abilities to finely control these systems was lackin : VIII.. Exit Interview With Licensee l The. inspection scope and findings were summarized on August 25, 1990, ! with those persons indicated in paragraph I.D. The AIT described the ' areas inspected and discussed in detail the inspection finding No dissenting comments were received by the license i
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. APPENDIX 1 PERSON CONTACTED
*B. Altman, Manager, Regulatory Compliance l C. Backes, Senior Specialist, RWCU & Hydrogen Water Chemistry G. Barnes, Principle Specialist, Unit 2, Operations M. Barton, Senior Control Operator '
J. Blackburn, Maintenance Engineer (Electric Motors) ,
*C, Blackmon, Manager, Operations ' *J. Boone, Principle Specialist, Human Performance Evaluation Systems ; *S. Boyce, Supervisor, ECCS Systems Engineering r *W. Bracey, RPS/PCIS and Nuclear Boiler Instrumentation System Engineer P. Brown, Reactor Recirculation System Engineer *A. Cheatham, Manager, Environmental and Radiation Control K. Chism, Shif t Operating Supervisor , *K. Core, Controls and Administration *R. Creech, Manager, Unit 2, I&C Maintenance !
J. Criscoe, Engineer, Motor Operated Valves
*W. Dorman, Manager,-QA/QC D. Evans, Control'0perator !
P. Flados, HPCI System Engineer R. Geise, Manager, Simulator Tra!ning P. Gore, Nuclear Boiler System Engineer M. Grantham, Senior Engineer, Nuclear Engineering Department
*J. Harness, Plant General Manager, Brunswick E. Hawkins, Senior Specialist, Simulator Training A.'Hegler, Supervisor, Radwaste/ Fire Protection - Operations H. Hewitt, I&C Technicir,'i *J. Holder, Manager, Outsge Management and Modifications t *B. Houston, Senior Specialist, Emergency Preparedness ' * S nes, Manager, On-site Nuclear Safety T. Jones, Specialist, Regulatory Compliance *R. Kitchen, Manager, Unit 2, Mechanical Maintenance *J. Leviner, Manager, Engineering Projects W. Link, Generations Specialist, Regulatory Compliance * Moore, Manager, Projects M. Morris, Control Operator *J. Moyer, Administrative Assistant to the Plant General Manager J. Munday, Shift Technical Advisor, Operations l P. Musser, Manager, Maintenance Staff *J. O' Conner, Technical Support * Paulk, Training l * Peeler, Manager, Planning and Scheduling S. Smith, Manager, Unit 1, I&C Maintenance I i
S. Smith, Turbine Systems Engineer
*R. Starkey Jr., Vice Prealdent, Brunswick Project L. Van Kleek, Control Operator i
*R. Warden, Manager, Maintenance i
*G. Wertz, Acting Supervisor, Reactor Systems Engineering L. Wheatiey, Supervisor, ISI/IST Engineering i
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Appendix 1 2
*K. Williamson, Manager, Nuclear Engineering Design-L. Witchen, Project Engineer . Mechanical .-
*A. Worth, Manager, Balance of Plant System Engineering Other Organizations:
*E. Scott, Operations Engineer, GE- ..
* Attended Exit Interviw on August 25, 1990 -
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APPENDIX 2 ACRONYMS AND INITIALISMS I AIT Augmented Inspection Team , ARI All Rods In l ATWS Anticipated Transient Without a scram l AUTO Automatic ; BWROG Boiling Water Reactor Owners Group ! CAB Cabinet ' , CBP Condensate Booster Pump l CFR Code of Federal Regulations 4 CHAN Channel CO Control Operator CRD Control Rod Drive DC Direct Current D-P Differential Pressure ; EAL Emergency Action Level ECCS Emergency Core Cooling Sysh m ; EHC Electrohydraulic Control E0P Emergency Operating Pror.edures , ERFIS Emergency Response Fac511ty Information System i ESF Engineered Safety Feature F Degrees Fahrenheit FSAR Final Safety Analysis Report ! FW Feedwater GE General Electric HPCI High Pressure Coolant Injection HR Hour I&C Instrumentation and Control I/P Current to Pneumatic ISI Inservice Inspection ISOL Isolation IST Inservice Testing JO Job Order , LCO Limiting Condition of Operation ' LER Licensee Event Report LOR Licensed Operator Requalification LPCI Low Fressure Coolant Injection l MOV Motor Operated Valve tiSIV Main Steam Isolation Valve MSL Main Steam Line MST Maintenance Surveillance Test NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation OPEVAL Operational Evaluation PCIS Primary Containment Isolation System PEP Plant Engineering Procedure psig Pounds Per Square Inch G'uge QA Quality Assurance yC Quality Control
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-Appendix 2 2 RCIC Reactor Core Injection Cooling RFP Reactor Feedwater Pump RHR Residual Heat Removal RPS Reactor Protection System RR Reactor Recirculation RWCU Reactor Water Cleanup SBGT Standby Gas Treatment System SCO Senior Control Operator '
SDV Scram Discharge Volume SIIT Scram Incident Investigation Team SIL Service Information Letter SJAE Steam Jet Air Ejectors SOE Sequence of Events SRV Safety Relief Valve STA Shift Technical Advisor SULC Startup Level Controller SULCV Startup Level Control Valve TCVFC Turbine Control Valve Fast Closure 15 Technical Specifications TSV Turbine Stop Valves WR- Work Request _ _
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ANNUNCIATOR PANEL 2-A-5
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MAINTENANCE SURvttt'act TEST SUMMARY sutET Date 1MST.PC1824N i PC1s High Condenser Pressure Trip Unit chan Cal i fdElE
! this Summary Sheet is provided only as an aid to the Shift Peroman and shall not be substituted for the entsting prerequisites and precautions stated in the procedur ,
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TEST DESCRIPTION
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this test provides a half. Crow t isolation signal to the. Primary containment Isolation Systes to:;ie for every condenser pressure easter
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trip unit being teste .. .
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j KEQUIRED P14N1_CONDIT10BS No other testa or natntenance are,in progress that could provide a hal !
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. Croup 1 isolation signal to the Primary containusnt Irtletion Systen logi ,
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ALTERATIONS TO PLANT SYSTRIB ' . . l j . This test may utilise the installation of a jumper between contacts 12
s of the associated Rela'y A718.K10A, .K103, K10C, or K100 to prevent the i J initiation of a half crog 1 isolation signal during calibratio l
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. This test may require the Low Cond Vac Le ic Key 19ek typass ,
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switchee A718 534A, .8348, .334C, and .8 0, to be operated.
i g ANWVNCIATORS EKP5CTEP AND AFFICTED INDICATIONS i RPS CHAN A TRIP CABINET TROUSLE (A.04 5 1) RPS CHAN & TRIP CABINET TROUBLE (A 04 6 1)
' CRP 1 180L IDCIC A/C TRIPPED (A.05 5 3)
4 CRP 1 ISOL IDGIC S/D TRIPPED (A.05 5 4)
' DC Inboard MSIV 14 sic light, A718.DS91., on RTC8 Panel P601 AC Inboard MSIV Logic light, A718.DS101, on RTG8 Panel P601 DC Outboard MSIV 143 1 c light, A718.DS131, on PTG8 Panet P601
' AC Outboard MSIV Logic light, A718.DS14 1. on RTC8 Panel P601 fp.*SIBLE TECMNICAL SPECIFICATIONS LCOs A Technical Specifications 140 may result from any instrument channel being under test for more than two hour MST.PCIS24M Rev. 4 Page 65 of 65 k !
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Figure 5 _ _
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O PCI/RCIC VALVE CYCLES TIME HPCI Valves RCIC Valves 2154 F001, F012 F045, F013 2155 F001, F012 F045, F013 2200 F001, F006, F011, F012 2201 F008 (throttled) 2216 F045, F013 2225 F008, F006 2227 '008, F006
2229 F013. F045 2234 F001, F006 2304 F045,F022,V8(2x) 2309 F001,F008 2S10 F008(throttled) 2311 F045 2318 F013, F045, F022 2321 F008 (throttled) 2323 F008, F006 2325 F001, F006 2327 F045, F013 August 20 0005 F001, F006 ;
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F001, F006 i
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Figure 6 o }}