IR 05000423/1990010
| ML20059D742 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 08/17/1990 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20059D737 | List: |
| References | |
| 50-423-90-10, NUDOCS 9009070164 | |
| Download: ML20059D742 (33) | |
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a U.S._ NUCLEAR REGULATORY COMMISSION
REGION I
Report No'.: 50-423/90-10 Dobket No.: 50-423 License N NPF-49 *
Licensee: Northeast' Nuclear Energy Company- i P.O. Box 270 Hartford, Connecticut 06141-0270 i
Facility Name:-Millstone Nuclear Power Station, Unit 3 I Inspection at: Waterford, Connecticut il
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j Inspection .
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Conducted: ' June 12 through July 23, 1990 -^
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' Reportin Inspector:
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Kenneth' S. Kolaczyk, . Resident Inspector, Millstone , '
Inspectors: -William J. Raymond,' Senior Resident Inspector,, Millstone .
Kenneth:5. Kolaczyk, Resident Inspector, Millstone 3 David H. Jaf fe, Project -Manager, NRR/PDI-4 Peter J. Habighorst, Resident _ Inspector, Millstone 2-
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Francis I. Young, Senior. Resident Inspector,= Three Mile Island, U it' l i Approved by: # dd/ M b $7/7/9C +
Donald R. Haverkamp, Chief- 'Dat '
. Reactor Projects Section tiA-
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Division of Reactor ProjectsL
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Inspection Summary; Impection on June 12 --July 23, -1990 (Inspection- Report No. 50-423/90-10)
q Areas Inspected: Routine resident inspection at M111stoneL3 during normal and- l backshift work periods of plant operations; maintenance and surveillance;
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security; engineering and technical' support; radiological controls; and safety,
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assessment and quality verification, l g
Results: See' Executive Summar !
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'l 9009070164 900823 i j gDR ADOCK0500gy3 <
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EXEco' /E SUMMARY-Plant Operations (Modules 71707,937]P) *
Operators: responded well to a loss of power to protection set I and thereby l prevented a reactor plant trip. The licensee has taken appropriate action to -
prevent inadvertent disabling of safety-related equipment. Additionally,_the }
inspector closed four NRC items of in'ere'st 50-423/87-08-01, 50-423/87-21-03, 50-423/89-08-01, and 50-423/89-14-0 i Radiological / Chemistry Controls (Module 7 ?07) ;
The licensee has taken appropriate action,to clean up a minor spill at th refueling water storage tank of contaminated fluids from a leaking flang .j Cleanup and environmental assessment of-the impact of the spill was determined to be acceptable. The chemistry department is _atte.npting to , identify the source of a minor .05 gallons per day steam generator tube leak. Actions that have been taken to identify the source 'have been determined to be appropriat .
Maintenance / Surveillance'(Modules 61726,62703)
An inadequate surveillance procedure lef t air conditioning units which cool both trains of safety-related equipment inoperable for _ eleven- hours. A tem-porary waiver of compliance was issued when the supplementary leak collection and release system (SLCRS) could not develop its technical specification re-quired air flo Security (71707)
No significant findings were noted during this report perio "
Engineering / Technical Support (Modules' 37701,93701) '
y No- significant findings were noted during this _ report period. One item,
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50-423/84-04-02, was closed regarding piping seismic analyses, t Safety Assessment / Quality Verification (Modules .37701, 71707, 90712, .92700)
A review of_ safety evaluations;did not identify significant weaknesses- although- f a few lacted the. supporting. detail necessary to arrive at the conclusion of _no J unreviewed safety questions. Followup of licensee corrective actions contained: -
in Licensee Event Reports (LERs) revealed that correctiveL actions were'not:com-pleted as stated in LER 90-13. A violation was issued regarding this matte ,.
One,. item, 50-423/88-15-01, was closed.concerning resin-procurement and' storag t i
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TABLE'0F CONTENT PAGE- [
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- 1.0: P l a n t : Op e ra t i on s Re v i ew . . . . . . . .. . . . . . . . .. . . .. . . . -. . . . . . . . . . -. . . . . . . . . . . . . . -1; j i
' 2.0 NRC-Inspection Activities....._..........................................
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-_' Plant 0perations (IP-71707/93702)* ....,......(............-..............
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3.1 Control Room Observations............................. ........ . . 2 ; Plant-Tours....-......s ...-....................................... '3 1 3.3'! Review of Plant Incident Reports ............................... L '
- 3.3.1; PIRL3-90-85, Safeguards Equip _ ment Actuation 1 Failure i 3.3.2- PIR 3-90-113, Plant Transient Caused by Power Supply- -t Failure.............................................._ -l4
~ 3. 4' P revi ou sly Iden ti fi ed I tems . . . . . . . . . . . . . . . . . . . . .>. . . . . . . . . . . . . . . . 5 ',
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3. (Closed): Unresolved Item 50-423/87-08-01: Licensee Actions Taken to Identify Deficiencies-in: Plant .
. Equipment'Which Place Reactor in Technical-
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Speci fication' Acti on ; Statement. . . . .' . . . . . . . . . . . . . .:. . . 5 -'
3. (Closed) Unresolved Item. 50-423/89-08-01:'. Imprope Tagging of Diesel Generator Equipment............... '6" 3. .
(Closed) Open: Item 50-423/89-14-02: 0perabili.ty ofi l Diesel Generator _ Following'11aintenance. . . . . . . ... . . . . . 7 3. (Closed) Unresolved Item 50-423/87-21-03:TAdequacy of '
" Licensee Boundary Valve Controls Following System -
LRestoration.. . ................ :c... . ....,...~.... L7' <i
- 4.0 Radi ol og i ca l - Con trol s l( I P 71707) . <-. . -. c . . . . . . . . . . _ . . . . .-._ , . . 3 . . . . . . . . : ; 8
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4.1 Minor Leakage of Contaminated Fluids Identi fied. .. .. . . . . . . . . . . . . .: 8 ;
4.2 Steam Generator. Leakage ~ Identified..............................- i8-5.0' Maintenance / Surveillance.(IP 62703/61726)............................
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5.1 Observation of Maintenance Activities.................;..........- 9l
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5.1.1- AWO 390-12860, RAK SET Channel #1 Power Suppl ,
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Failure.....................................~........ . 10:
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5.2 ' Observation of Surveillance Activities.......................... 11'
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5. Both Trains of Accident Filtration Inoperable.........
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l- 5. Inadequate Surveillance of Engineered Safety Features W - Ai r 'Condi tioning Heat Exchangers.' . . . . . . . . . . . . . . . . . . . : 14 e 1 l
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Table of Contents ,
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PAGE 6.0 Engineering / Technical Support'(IP 37701/92701)....................... 18
6.1 Plant Design Modifications,..................................... 18
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6. (Closed) Unresolved Item 50-423/84-04-02: Piping
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S e i s m i c A n a l y s e s . . . ,. . . . . . . . . . . , . . . . . . . . . . . .. . . . . . . . . . . 18' [
7.0~ Security (IP 71707)....................................-................ 19 8.0 Safety Assessment / Quality Verification (IP_37701/71707/90712/92700). 19 , .1 Committee Activities.............................. . ........-..... 19-
8. Audit of- Licensee Safety Evaluations Conducted Per 10 C F R 5 0 . 5 9 . . . . . . . . . . . . . . . . . . . -. . . . .. . . . . . . .. . . . . . . . . 20 8 . 2 . P e r i o d i c R e p o r t s . . . . . . . . . . . . . . . -. . . . . . . . . . . . . . . . . - . . . . . . . . . . . . . . . . 22 ,
8.3- Licensee Event Report Review.. 4........u...................... ~23 8. LER 90-13-00, Manual Reactor Trip-Oue to Loss of
. Condenser ~ Vacuum.................................... 23 1 8. LER 90-14-00,- . Manual' Reactor Trip. Due to Loss 'of Condenser Vacuum.................................... 24 8. LER 90-15-00, Feedwater Isolation When' Opening Mai ?
Steam.lsolation Valves.............................. 25 8. LER 90-16-00, "B" Steam Generator Low-Low Actuation... 25 8. LER.90-17-00, Both Trains of Safety Injection Inoperable Because of Personnel l Error.............., -25 1 8. LER 90-18-00, Improperly Established Fire Watch.......- 261 !'
8.-3. 7 LER 90-19-00, Reactor Trip Due to. Dropped Control Rod, -
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'8. LER 90-20-00 and~LER 90-23-00,'Both' Trains.of'
Engineered Safety. Features Equipment inoperable...... 26 8. ,
LER 90-22-00,- Mi s sed Hourly Fi re _ Watch. . .-. . . . . . . . . . . . . 27 '
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8.4- Quality. Assurance Issues'C1osed................................. 28 8. 4.~ 1 '(Closed) Unresolved Item:50-423/88-15-01i Licensee . -l Shelf Life' Corstrols;ofl Condensate Polishing: Resins. . 28 4 ,
g 8.5 Management Meetings................ 2....... 4 .................. 29 t'
- The. NRC inspection manual inspection. procedure (IP): or1t emporary instructions (TI) that was used as inspection guidance'isisted fo'r each1applicablefreport ~
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DETAILS 1.0 Plant Operations Review 1he Millstone Nuclear Power Station Unit 3 (Millstone 3 or the plant) was at 80 percent of rated thermal power at the start of the report period due to problems with feedwater heater level control valve The level control valve problems were due to excessive condensate drain flow to the 1A and 1C feedwater heater trains, which resulted when the IB feedwater heater-string was taken out of service to investigate leakage through the IB feedwater heater relief valv When subsequent investigation revealed that the relief valves on all three high pressure feedwater heaters were -leaking, the licensee elected to re-move all three feedwater strings from service, remove the relief valves, and replace the valves with bypass spool pieces until replacement parts could arrive. Since the feedwater heater bypass line could transmit only a reduced water flow to the generators, the turbine was taken off line on June 15. Once the relief valves were, removed, bypass spool pieces with pressure monitoring devices were installed in place of the relief valve The condensate feedwater heaters were subsequently restored to service and the generator was resynchronized to the grid on June 16. Full power was reached on June 1 On July 3, the primary and backup power supplies to reactor protection set 1 failed. The resulting letdown isolation and feedwater oscillations caused a rapid plant transient which operators accurately diagnosed and brought under contro On July 19, the licensee declared an Unusual Event emergency classifica- ! tion and began preparations to shut down the plant, when both trains 01 the supplementary leak collection and release system (SLCRS) were deter- 1 mined to be inoperable when the technical specification required flow rate could not be niet on both trains. Subsequent modifications to a backdraft
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damper on the B train increased the air. flow on.that train to the techni-cal specification required level which restored _ that system to service and terminated the Unusual Event. When further testing demonstrated that even with the reduced air flow rate the SLCRS design function could be met, a temporary waiver of compliance was. submitted to the.0ffice of Nuclear Reactor Regulation (NRR). The temporary waiver was approved'on July 23 to allow plant operation at the reduced air flow pending issuance of an emer-gency technical specification change. At the end of the report period, Millstone 3 was at 100 percent of rated thermal powe .0 NRC Inspection Activities During the weeks of June 11-15 and June 25-29, NRC regional inspectors conducted a review of engineering support for the Millstone site. Pre-liminary results did not identify any significant weaknesses. The NRC inspectors held exit meetings on June 15 and June 29, and their findings will be documented in inspection report 50-423/90-09. On June 28, NRC
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resident, regional anc( headquarters personnel conducted a meeting with the licensee in Berlin, Connecticut. Meeting topics concerned licensing is-sues and the NRC inspection program at the Haddam Neck and Millstone facilitie The inspection activities during this report period included 204 hours of inspection during normal activity working hours. In addi-tion, the review of plant operations was routinely conducted during per-iods of backshif ts (evening shifts) and deep backshifts (weekends and midnight shifts). Inspection coverage was provided for 10 hours during backshif ts and 18 hours during deep backshif ts. An exit meeting which provided the results of this inspection was conducted on August 6, 199 ' 3.0 Plant Operations 3,1 Control Room Observations The inspector reviewed plant operations from the control room and i reviewed the operational status of engineered safety features equip-ment and other plant safety systems to verify safe operation of the plant in accordance with the requirements of technical specifications and plant operating procedures. > Actions taken to meet technical specification requirements when equipment was inoperable were re-viewed to verify the limiting conditions for operations were me Plant logs and control room indicators were reviewed to identify changes in plant operational status since the last review and to verify that changes in the status of plant equipment were properly communicated in the logs and record Control room instruments were observed for correlation between chan-nels, proper functioning and conformance with technical specifica-tions. Alarm conditions in effect were reviewed with control room operators to verify proper response to off-normal conditions and to 'i verify operators were knowledgeable of plant status. The-inspector ' reviewed red tags #1 and #2 associated with the repair of RAK SET #1 power supplies- and found that the tagouts were properly implemented in accordance with Clearance No. 3-2096-90. Trainees who were'mani-pulating reactor controls.were under instruction by licensed opera-tors. Operators were found to be. cognizant of control room ' indications and plant status during normal working hours and backshift observations. . Control room manning- and shif t staf fing were reviewed and compared to technical specification requirements. No inadequacies were identified.
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3.2 Plant Tours The inspector observed plant operations during regular and backsnift tours of the following areas: Control Room Containment Vital Switchgear Rooms Diesel Generator Rooms Turbine Building * Intake Structure , Auxiliary Building ESF Building Spent Fuel Building Main Steam Valve Building DWST Enclosure During plant tours, logs and records were reviewed to ensure compli-ance with station procedures, to determine if entries were correctly made, and to verify correct communication and equipment status. The plant areas that were inspected were found to be free of tools and miscellaneous combustibles, The painting of the spent fuel storage ; pool deck and adjacent areas significantly impr'6ved the appearance of that area and should aid in future decontamination efforts. Overall housekeeping was judged to be very good; no unacceptable conditions were identifie ! 3.3 Review of Plant Incident Reports j i The plant incident reports (PIRs) listed below were reviewed during i the inspection period to (i) determine the significance of the ! events; (ii) review the licensee's evaluation of the events; (iii) verify the licensee's response and corrective actions were proper; and, (iv) verify that the licensee reported the events in
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accordance with applicable requirements, if required. The PIRs - reviewed were numbers 3-90-85 through 3-90-115. .The following items j warranted inspector followup: PIR 3-90-85, 3-90-94, 3-90-95, j 3-90-97, 3-90-101, 3-90-105, 3-90-112, 3-90-113, 3-90-114 and ; 3-90-116. These PIRs are discussed in sections 3.3.1, 3.3.2, 4.1, l 5.2.1, and 5. . 3. PIR 3-90-85, Safeguards Equipment Actuation Failures- i
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This PIR documented the May 30 failure of valve 30SS-A0V28 to i close while performing testing per SP 3646A.9-1, " Slave Relay ' Testing Train B." Valve 30SS-A0V28 is in series with valve i 3QSS-A0V27, and both close upon receipt of a safety injection [ signal to isolate the non-safety-related refueling water storage ~ tank (RWST) recirculation pump suction piping from the RWS Upon failure of the valve to close, operators-immediately closed-valve 30SS-A0V27 to isolate the nonsafety-related pipin Examination of the valve revealed that a pin which is used to engage the valve hand wheel operator, to allow manual' operation, was partially inserted, rather than withdrawn to the fully retracted positio The partial insertion prevented automatic
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. operation of,tne valve. Once the pin was removed, the valve was stroked automatically from the control room, and then retested satisfactorily per SP 3646A 9- . The inspector was concerned about this event since a similar failure occurred during testing on September 26, 1989. Licensee investigation of the September 26 event determined that improper valve operation was the cause and concluded that an operator failed to' remove the pin after manual manipulation of the valv The-licensee subsequently placed a placard adjacent to valves 3Q55-A0V27 and 30SS-A0V28, which are the only two valves of this-design, with. detailed instructions on how to operate the valve manuall Recurrence of the failure suggests that imprope' valve operation may not be the caus The inspector noted that valves 3QSS-A0V27/28 are located outdoors adjacent to the refueling water storage tan The pin which engages the manual operator is consequently located in .an area where it could easily be pushed in inadvertently by an individual who may be working adjacent to the valve. The inspector noted that, as a result of
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the most recent event, the licensee has elected to remove'the pin from the valve and leave it hanging from a wire line adjacent to 30$S-A0V27/28. Manual operation will subsequently require placing the pin into the valve. The' inspector noted that the licensee's corrective action should prevent inadvertent manual engagement. The inspector had no further questions, 3.3.2 PIR 3-90-113, Plant Transient Caused by Power Supply Failure - During norinal operation at full power on July 3,1990, the primary power supply ~for reactor protection system channel #1 l (RAK SET #1) failed at'7:17 p.m. There was no impact on plant operations'since the backup power supply immediately supplied
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power to RAK SET #1. The failure was accompanied by the annunciator on the main control board " PROT &'CNTL PWR SPLY FAIL." 'The operators responded to the. alarm, in accordance with the alarm response procedure, and identified that RAK' SET #1 was the affected channel from the plant. sequence of~ events computer and by review of the power supply voltage indications at the protection channel cabinet Assistance was requested' from 'the instrument and controls (I&C) group to investigate the proble ! Routine operation continued until 7:37 p.m. when the backup power supply for RAK SET-#1 also. failed, resulting in a loss of' power to safety and control instrument The power failure caused a trip of associated safety channels, but a reactor trip did not occur, since the required coincident trips from redundant channels did not occur. However, the loss of power to RAK SET #1 did cause the reactor system letdown to isolate, a
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feedwater and steam generator level oscillation, a pressurizer
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x power operat.ed relief valve to cycle open once, and the steam dump system to fai , The rerators responded by taking manual control of feedwater flow co refill the generators; taking m::nual control of the control rods; selecting alternate control channels for affected parameters (pressurizer pressure', pressurizer level, feedwater flow, steam generator level); pla:ing the steam dump system in the pressure control mode; and reestablishing letdown flo The operators also reviewed status indications to assure that all reactor protection system (RPS) bistables were tripped and entered the associated technical specification action statement for affected systems and instruments. I&C personnel replaced a blown, fuse in the 120 vac feeder to the backup RACK SET #1 power supply, and power.was restored to the protection channel at 1:40 a.m. on July 4, 1990. The primary power supply was found to be failed and was left out of servic The inspector reviewed the . transient using the plant sequence of event report, logs, and records, and through interviews with operators. - No' inadequacies were identified regarding plant or operator response. The operators demonstrated good performance by averting a reactor trip on low steam generator leve Inspector review of the licensee investigation of the power supply failure is described in Section 5. ' 3.4 Previously Identified Items 3. .(Closed) Unresolved Item' 50-423/87-08-01: Licensee Actions Taken to Identify Deficiencies in Plant Equipment Which Place-the Reactor in a Technical Specification Action Statement - l This item documented that prior to a reactor startup on April 12,1987, _ the licensee failed to recalibrate the inter-mediate range nuclear instrumentation trip setpoint to its desired value, as required by technical specification action sta tement 2.2. The out of adjustment bistable had been previously noted during a reactor startup on April 11, 198 The licensee investigation of this event determined that per-sonnel error was the cause. Specifically, during the April.11' plant startup, operators observed the intermediate range bistables trip at 27 percent vice the technical specification
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stated value of 25 percen A' trouble report was . initiated; however, this fact was not entered into the shift supervisor's-log. Additionally, the trouble report was not-converted into a work order. Consequently, when the plant tripped at 6:18 and was restarted the same' day at 12:00 p.m.,-the licensee method of ensuring all technical requirements are met prior to startup (i.e., review of work orders, jumper bypass log, shif t supervisor log) did not identify the discrepancy to management
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personnel. A shift supervisor did discuss the anomalous nuclear instrumentation performance with the licensee duty reactor engineer; however, the engineer incorrectly determined that a recalibration was not require The need to recalibrate the nuclear instrumentation bistables was discovered by the Unit 3 reactor engineer during a post-trip review when the reactor tr'ipped again on April 12 at 6:08 The inspector was informed by licensee personnel that subsequent-to this event, shift supervisors have been instructed to administrative 1y log into technical specification action statements that could prevent plant return to full power if a significant power reduction occurred. The inspector noted that this policy appears to be effective since plant startup while in-an action statement has not occurre The inspector concluded that the licensee's policy of logging into technical specification action statements administratively appears to be sound, and therefore, this item is close ' 3.4.2 (Closed) Unresolved Item 50-423/89-08-01: Improper Tagging of Diesel Generator Equipment This item tracked the licensee's investigation of improper tagging of the B diesel generator support equipment during a maintenance evolution. Inspector ~ review of tagout 3-3880-89 which was written to support the maintenance evolution noted two items; tag 26 (Jacket water circulation pump switch - 3EGS*P2B) and tag 28 (generator space heater. switch - 3EGS*H2B) were incorrectly set. The tag log sheet for-3-3880-89 showed 3EGS"P2B and 3EGS*H2B in the "off" position (both switches were found to be in the "on" position). The circuit breakers for 36GS*P2B and 3EGS*H2B were verified to be in the' correct "off" position. When informed of the discrepancy, the licensee promptly restored 3EGS*P2B and 3EGS*H2B to their correct "off" position and generated plant incident report (PIR) 89-7 The licensee investigation of this issue contained in pIR 89-76 concluded that the improper tagging was caused by personnel error. The individual who performed the tagout was counseled by the operations supervisor on the importance of properly tagging equipment, and the event was discussed at a weekly. supervisor's meeting, inspector review of equipment tagging and tagging controls subsequent to this finding has identified that equipment power supply breakers and switches have been correctly tagged, i.e. , open/off, racked out, etc. Therefore, the' inspector considers the previous findings not a generic tagging concern and this issue is close ' - - - - - - - - - - - - - - - - - - - - - ._ . _ _ - . .. - _-
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3.4,3 (Clqsi d) Open Item 50-423/89-14-02: Operability of Diesel Generator Following Maintenance This item documented an inspector's observation that following maintenance activities performed on the emergency diesel generators, the licensee did not start the diesel to verify operability. The inspector was concerned that the licensee's method of isolating and re' storing the diesel generator to service removal and reinstallation of the control power fuses for the diesel generator breaker, without performing a subsequent diesel start, could -leave the diesel inoperable .if a defective fuse was reinstalled into the control power circui The inspector discussed his concern with a licensee systems engineer who reviewed the breaker control power schematic with- 4 the inspector, . Review of the- schematic revealed that if a defective fuse was installed, the two annunciators which illuminate when the fuses were removed - ioss of control power on main board 8, and diesel generator train B bypassed on main-board 1 would remain illuminated. The inspector concluded that if these annunciators, remained illuminated when the fuses-were reinstalled, operators would investigate the cause before declaring the diesel operable. Therefore, the inspector determined that running the diesel to verify operability following fuse restoration is an unnecessary start on the diesel
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which would provide limited benefit. This item is close . (Closed) Unresolved Item 50-423/87-21-03: Adequacy of-
-Licensee Boundary Valve Controls Following System Restoration i
This item documented NRC concerns regarding the licensee control of system status following restoration from work activitie ; This concern was identified when a spill of contaminated fluid occurred during reactor cavity draindown when caution-tagged l valves in the draindown flowpath were left open vice the required closed position.
l The inspector discussed this event with an operations supervisor who indicated that personnel error was the cause. The operators who verified system tagouts through review of system integrity l- prior to the draindown evolution did not verify that .the
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L caution-tagged valves were closed. The supervisor stated that i he considered the' event to be an isolated occurrence since no spills due to inadequate system tagging restoration have occurred since the initial November 11 event. Therefore, no modification is planned to the current. method of establishing system flowpath integrity, such as performance of a= valve lineup prior to use of a syste After conducting a review of plant incident reports (PIRs), from January 1,1987 to June 1,1990, the inspector noted that this event does appear to be isolated since no similar restoration .- ..
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problems occ.urred during the time period. Therefore, the inspector concluded that a generic' concern does not exist and the licensee's present method of establishing systern integrity through review of tagout records is adequate. This item is close .0 Radiological Controls 4.1 Minor leakage of Contaminated Fluids Identified i On June 20, the licensee identified low-level contamination in soil samples near the' refueling water storage tank (RWST). The samples were identified as part of the monthly routine onsite environmental program. Licensee investigation identified the source of contamina-tion as a leak on the= flange of spool piece 2-SIH003-46 which is ; located on the emergency core cooling system recirculation.line
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located against the east side of'the RWST.- The spool piece leakage was not readily apparent to visual examination because of insulation which surrounded the join ,
Surve.,s were conducted for the area below 2-SIH003-46-(10 feet X 15 feet); adjacent storm drains and asphalt; and the recirculatio line. No activity was detected ,in the storm drains; however, activity on the leaking spool piece was 5000-30,000 dpm/100cm2 and-7.17 X 10-3 pCi/gm on adjacent soil samples. Radiation. levels on the spoolpiece were 2S millirem /hr. The area was properly postea and controlled as a radiation area and plant incident report:3-90-105 was initiated to document the even Licensee cleanup efforts consisted of repair and decontamination of the spool piece and removal of the contaminated. soil. The licensee's l assessment of the environmental impact of the spill is contained in ; l inspection report 50-423/90-11. The inspector.noted that access to areas around the RWST that are susceptible to . leakage have been sub-sequently roped off and now require. health physics permission prior to entr The inspector reviewed the licensee's response to this event and con-sidered the actions taken to be acceptable. The inspector noted that if the licensee -had not conducted environmental monitoring of this area, the leak may have not been noticed for an extended period of time. The inspector considered that the licensee environmental moni-toring program significantly decreased the impact of this spill and
'had no further question .2 Steam Generator Leakage I.rentified On June 26, 1990, while performing an analysis of a gaseous' sample !
from the steam jet air ejector vent, chemistry personnel detected activity at the level of 3X10-8 pCi ml. .This activity is one-tenth , of the 10 CFR 20 limits for these isotopes for discharge-into an i
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unrestricted areq. The activity consisted primarily of Xenon 133 and-Xenon 135 fission products, which have a four-hour and nine-hour half-life, respectivel Further sampling conducted on individual steam generators did not identify any detectable activity; however, _ samples from condensate deminera'lizer beds found-the isotope Cesium 134 at concentration of 1X10-7 uc/ml. Using leak measurement tech-niques by comparing the level of isotopes in the primary and second-ary systems, chemistry department personnel have estimated the leak rate to be .05 gallons per day or .003 percent of the technical specification limit of 1-gallon per minut Since the June 25. discovery, the leak rate has not changed and chemistry personnel are trying to identify the steam gen *ator with the tube leak. The inspector noted-that grab samples from the air ejector vent must be taken to calculate a leak rate _since the -i activity level is below the air ejector radiation monitor background level of.1X10-5 uc/ml. -The inspector has no questions regarding the licensee tracking of the steam generator leakage and will continue to monitor licensee efforts in this are ' 5.0 Maintenance / Surveillance 5.1 Observation of Maintenance Activities
'The inspector observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of administrative and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retes The following activities were incluaed: --
AWO M3-90-05817, B safety injection pump. discharge header relief, June 12, 199 AWO M3-90-11782 3 HVQ * ACUS 28, ESF self-contained air conditioning unit, dated June 25, 1990
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AWO M3-90-12157 3HVQ-ACUS 2A, ESF self-contained air conditioning unit, dated June 29, 1990
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AWO M3-90-11254, Emergency diesel generator A monthly required , maintenance, dated June 27, 1990'
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AWO 3'")-12860, RAK SET Channel #1 Power Supply Failure, dated July 3, 1990
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AWO 390-12866, RAK SET #1 Power Supply Replacement, dated July 5, 1990 No significant observations were mad .1.1 AWO 390-12860, RAK SET Channel #1 Power Supply Failure ! The primary power supply for reactor protection system channel
#1 (RAK SET #1) failed at 7:17 p.m. on July 3 during plant operation at full powe There was no impact on plant operation l
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i because a hi.gh auctioneering circuit caused an automatic switchover to the backup power supply upon failure of the primary. _However, 20 minutes later the backup power supply also apparently failed, causing a loss of power to RAK SET #1. Plant operators stabilized the plant during the ensuing transient (see ; section 3.3.2). I&C technicians identified a blown fuse in the :' feeder to the backup power supply and the power to RAk SET #1-was restored at 1:40 a.m. on July 4. The inspector reviewed licensee actions to investigate the power supply failure The licensee found that the primary power supply had failed internally. The normal output of 26 VDC was found failed to 1 VOC. Action completed during this inspection period included removal of the failed (Pacific Electric) power supply,.which was reviewed by licensee personnel with assistance from the vendor to identify the failure mechanis Licensee review identified that the secondary power supply for RAK SET #1 remained operabl.e, but the 20 amp fuse in the supply line from vital bus #1 (VB1) was blown. Both the primary and secondary power supply are fed from the common source, Circuit
#3 of the VBl. The licensee disconnected the primary supply from the circuit, verified .from the plant drawings that the correct replacement fuse was 20 amps, and tested the secondary supply prior to replacing the fuse and restoring the RAK SET #1 to servic Licensee investigation identified the following apparent anomalies during the troubleshooting and repair efforts: There was no coordination in the fuse and breaker sizing for the RAK SET #1 120 VAC power supply, in that the feed from VB1 was fused at 20 amps, the System 7300-process cabinet breaker was set for 35 amps,- and the npower supply had an internal breaker set for 30 amps. The current drawn by.the circuit during normal system operation is about 10 amps, and the anticipated maximum loading is expected to be less than 15 amps. This configuration is typical for. the other protection system channels. The inspector noted from ,
a review of drawings'12179-EElBF and vendor drawing 8795001-that the installed circuitry was in accordance with the design configuration. This item remained open at the end of the inspection period pending completion of the licensee's review of the circuit design and the development of a proposed design change' to assure proper circuit . overload protection coordinatio ! The VB1 20 amp fuse failed after.20 minutes of operation under the secondary supply. Examination of the secondary ' supply found it to be operating properly. The licensee concluded that when the primary supply failed because of a i
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. short 1,n the primary coil of, the transformer for the power supply, it continued to draw curren The continued cur-rent load caused the VB1 power supply fuse to fail, This deenergized the backup power supply which resulted in the ' plant transient', y On July 21, the licensee installed a replacement primary power supply drawer, obtained from stock, When instrumentation and controls (I&C) technicians closed the power supply DC output _
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breaker, electrical sparking was heard. The technicians promptly opened the DC output breaker _and de-energized the power supply drawer. Examination of the drawer revealed that.the sparking was caused by the drawer. components contacting wire screen mesh that was installed over--the lower power ' supply. The I&C supervisor stated that the screen mesh was _ installed during- r construction to prevent debris from. falling'into the cabine The drawer was removed for bench testing, which did not identify any damage caused by the short, Examination of the remaining . power supplies revealed that due to the 1-2" air gap that existed between them, recurrence of the event was not plausible on these cabinets. The I&C supervisor indicated that th licensee will remove the screen mesh between the two power supplies before restoring the primary drawer to servic Licensee actions to return the primary supply to service had not been completed as of the end of the inspection perio Restoration of the primary power supply, and licensee resolution of the coordination and loading issues, will be reviewed during a subsequent routine inspectio .2 Observation of Surveillance Activities The inspector observed portions of completed surveillance tests to assess performance in accordance with approved procedures and Limit-ing Conditions of Operation, removal and restoration.of equipment, and deficiency review and resolutio The following tests were reviewed:
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OP 3626.13, Service Water Heat Exchanger Fouling Determination
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SP 3641A 1, Fire Protection Water System Valve Cycle and-Lubrication
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SP 36141.1, Supplemental Leak Collection and Release System , Operability Test Procedure SP 36141.1 is discussed in Section 5. Procedure OP 3626.13 is discussed in Section 5.2.2, 5. Both Trains of Accident Filtration Inoperable On July 16, 1990, the "B" train of the supplemental leak collec-tion and release system (SLCRS) failed its monthly air flow verification surveillance test per SP 36141,1, " Supplemental l
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Leak Collection and Release System Operability Test." The measured air flow was 8075 cubic feet per minute (cfm) vice the technical specification (TS). surveillance rate of 9500 cfm plus or minus ten percent (or a minimum flow of 8550 cfm).
Consequently, the "B" train of SLCRS was declared inoperable. A plant incident report (3-90-112) was-initiated, and the plant
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entered the corresponding action statement (TS 3.6.6.1.a) requiring restoration of the train or shutdown of the plant in seven. days. . The licensee initially suspected clogged filters at the cause based on previous similar surveillance results and replaced the high efficiency particulate air (HEPA) filter However, change out of the HEPA filters did not significantly increase the fiow rate. Investigation of other components.in the "B" train, such as dampers, air ducting and the associated fan, did not reveal the reason for the flow degradation ~. 1 Since the root cause could not be isolated to the "B" train, the licensee began to investigate components that were common to ! both trains which could effect system flow rates. On July 19, -[ 1990, the licensee elected to perform the monthly surveillance ] on the "A" train to verify its flow. (The "A" train was last I tested satisfactorily on July 4.) The "A" train of SLCRS also ' failed its monthly surveillance on July 19. The licensee immediately declared the second train inoperable and entered i Technical Specification (TS) 3.0.3 action statement requiring ; plant shutdown within six hour While the operations staff began preparations to remove the l plant from service, the licensee elected to retest the "B" train of. SLCRS, based on engineering and vendor recommendations, with-the "B" train backdraf t damper (3HVR-DMPB 13 B) failed, full ope ;! Normally, the open position of this damper is 85 percent full open allowing some back pressure for the associated fa When tested with the damper ' fully open, the system flow rate l
- was 8645 cfm or 91 percent,.which met the requirements of TS 3.6.6.1, With the B back draft damper open, the possibility '
existed that air flow from the A. train could recirculate through i the B filter system and reduce the effectiveness of the A trai Therefore, the licensee had to consider the A train inoperabl ; This action, however, allowed the licensee to exit the TS 3. . action statement but the seven day limiting condition for ! operation (LC0) of TS 3.6.6.1,. which applied to the A train, remained in effect. This action was deemed acceptable since ! calculations to establish the initial design basis sh' ed that
. the SLCRS could perform the accident mitigating funct an at a ,
l 4700 cfm flow rate. Thus, the TS 3.0.3: action statement was ! I exited at 3:39 p.m. on July 19,
Continuing evaluation by plant engineerirg concluded that the j
. system could still perform its design basis function. As s described in the final' safety analysis report (FSAR), the SLCRS 2
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is designed to produce a negative pressure of one-quarter-inch water gauge (wg), with respect to the outside environment, in the contiguous buildings (annulus area) to the primary containment within 60 seconds af ter a postulated design basis - accident occurred. The test to verify this function is satisfied requires that each train of SLCRS be started and, within 50 seconds, draw a negative one quarter-inch wg in the annulus area. This test i's performed per the technical specifications every refueling outage. As noted above, the flow rate necessary to perform this safety function is 4700 cfm from either trai The licensee determined that the original TS requirement of 9500 cfm was obtained from the name plate flow rate on the SLCRS exhaust fan and not. actual test results. On July 20, 1990, the licensee performed the draw down test at approximately 7040 cfm and produced the required negative pressure in the annulus area within 30 second The test was witnessed by NRC inspector On July 20, 1990, the licensee briefed the NRC of its findings and position, and based on,the testing and engineering evaluations, submitted an Application for Licensee Amendment and Request for . Temporary Waiver concerning the requirements of .6.6.1. The application would revise the SLCRS flow rate from 9500 cfm i 10 percent to a flow rate range of 7600 to 9800 cf This-flow range was picked since it was adequately bounded by the design basis and actual performance flow valves. On che morning of July 23, 1990, the NRC staff verbally granted the Temporary Waiver of Compliance. This waiver was subseq'uently documented in a letter from the NRC to the licensee that afternoo To assess the adequacy of the licensee actions with respect to ' l ' safe operation of the plant, the inspector verified the licensee's engineering calculation, witnessed-portions of SLCRS surveillances, and discussed and reviewed the licensee's i ! application for temporary waiver. Review and partial walkdown of the system was performed after restoration of the SCLRS to its normal lineup. The inspector review of the engineering- . L calculation on the test flow envelope found the calculation to be correct.
l < i Inspector review verified that the removal and subsequent ! restoration of the "A" train and the failed open "B" backdraf t l damper was conducted and documented in accordance with licensee procedures. The surveillance procedure was performed properly, as was the revision to the surveillance procedure. Discussions ' with licensed operators demonstrated acceptable understanding of-the required operator actions in event the system was starte , The inspector reviewed the waiver of compliance, as it directly relates to plant operations regarding technical specifications, and determined that the licensee's actions were correc I
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. The inspector noted that previous surveillances have demon- , strated that the SLCRS exhaust fans have been unable to achieve t 100 percent (9500 cfm) flow. Thus, the licensee could have taken more' timely action to identify that the technical * specifications value of 9500 cfm was not a realistic valu In general, the licensee actions were considered appropriate to : resolve the issue on an interim basis. The licensee is investigating the reasons why the flow rate decreased below the previously acceptable values. Initial indications have revealed that neoprene damper seals which are used to ensure a leak tight sealing surface exists, have deformed due to age. Licensee engineers have stated that improper damper seating could reduce system flow rate. The inspector will continue to monitor the licensee investigation of this matte . Inadequate Surveillanc- of Engineered Safety Features Air Conditioning Heat Exchangers On two separate occasions,' June 14 and July 5, 1990, the licensee determined that as a result of fouling and tubesheet damage, (documented in plant incident reports 3-90-94, 95, 97,
-101,134, and 115), heat exchangers for both trains of air-conditioning units which cool emergency core cooling system components were inoperable. The air conditioning units are Q/A Category I components that are powered from a vital power supply. These units start automatically when the ESF components that they are designed to cool receive a start signal. . The units are designed to maintain the air. temperature of the ESF cubicles in which the safety related components are located-below 104 degrees F. Licensee engineers postulated that, as a result of the heat exchanger fouling and damage that- had occurred, if a design basis accident occurred, the air conditioning units could not have maintained the temperature of the ESF cubicles below 104 degrees F. Therefore, the safety-related components located in the cubicles would he n had to operate outside the design environmental qualification tempe ra ture. This may.have resulted in damage to the ESF components depending on the length of time in which they were operated and the cubicle temperature-increase. The two separate events are discussed belo June 14, 1990 Event While performing a quarterly fouling determination per SP 3626.13 " Service Water Heat' Exchanger Fouling. Determination," on:
the heat exchanger for air conditioning unit 3HVQ-ACUS 1B, the differential pressure across the heat exchanger was noted to be 10 psi, which was 4 psi above the action range specified in SP-3626.13, 3HVQ-ACUS 1B cools the area in which the "B" safety-injection, residual heat removal, and quench spray pumps are
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15 . located. Op.erators initiated plant incident report (PIR) 3-90-94 in accordance with the instructions contained in SP 3626.13 to inform engineering so an operability determination could be performe On June 15, while engineering was performing the operability evaluation on the "0". train heat exchanger, operators removed the
"A" safety injection and quench spray pumps from service at 3:38 a.m. to perform routine surveillance and piping modifica-tions. -When engineering determined that the high differential pressure was due to excessive fouling, operators cancelled the work that had nat been completed on the "A" train and restored the system to operable status by 2:45 p.m. that afternoon. There-fore for an eleven hour period, both trains of safety injection lacked their necessary support equipment which would enable them to function in all stages of an accident, and the safety injec-tion equipment was technically inoperable. A draindown and cleaning of the "B" air conditioning heat exchanger was subse-quently performed and it wa.s declared operable on June 16 at
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2:24 Second Event July 5,1990 I Following the discovery of the fouling.on the 3HVQ-ACUS 1B heat exchanger, the licensee inspected the heat exchanger for the A safety injection, quench spray, and residual heat removal pumps - 3HVC-ACUS 1A, and the heat exchangers for the "A" and'"B" train recirculation spray system air conditioning units, 3HVQ-ACUS 2A and 2 Inspection of 3HVQ-ACUS 1A did not identify [ any fouling; however, inspection of 3HVQ-ACUS 2A'and 2B revealed extensive fouling and tube sheet damage in both heat exchanger- ' divider plate The damage consisted of erosion of a pre-- ! existing 1/4" diameter drain hole to 1.5" in~ diameter. The hole is used to drain the upper portion of the heat exchanger during maintenance evolutions. Additionally general wastage was also r,oted around the enlarged hol The licensee repaired the tube sheet by drilling out the defective areas and replacing-the damaged section with a monel . patch attached to the divider plate by screws. Calculations
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performed by licensee corporate engineering determined that the excessive heat exchanger fouling, coupled with the reduced
- service water flow which bypassed the tubes by going through the divider plate, rendered the air conditioning units incapable of removing their designed heat load. Therefore, if a design basis-accident occurred, the recirculation pump equipment may have been damaged due to excessive temperature buildup, which could render both trains of recirculation spray inoperabl l
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-Inspector Re. view Inspector followup of these events consisted of interviews with licensee operations, engineering, and maintenance and management . personne The inspector noted that the licensee conducted a service water heat exchanger monitoring program per SP 3626.13 since the start of commercial operation. in August 1986. This was well before the NRC recommended a program for heat exchanger q monitoring as outlined in generic letter 89-13, dated July 18, 198 According to the licensee engineering supervisor, performance of the heat exchangers has been good. Therefore, the heat exchangers have-never been-opened and inspected because of fouling. Routine inspections of the exchangers were considered i but not performed because it was perceived by maintenem:e personnel to be a time-consuming evolution due to the heat exchanger design, and one.that could not be performed within the 72-hour limiting condition ,for operation time limi Inspector review of heat exchanger performance since January .
1990 revealed that on several occasions, such as January 4, 1990 '
(reference PIR 3-90-002), a high differential. pressure was recorded across-the heat exchangers. However, upon further investigation with a controlatron flow measuring device, the-high differential pressure across 3HVQ-ACU2B was attributed to excessive flow caused by a mispositioned heat exchanger throttle valve, SWP-V696, which_was left open vice throttled. Once operations personnel throttled the valve to its desired position, differential pressure returned to the accepted valu The inspector noted that the throttle valve is normally in a closed position; however, the valve in this instance was required to be open since pre:;sure control valves PV11382 an !
PV11381 which normally control service water flow through the heat exchanger were failed closed due to incorrect pressure setpoint This condition also existed on the other three heat exchangers. According to a system engineer,. readjustment of the pressure control valve setpoints and a modification to the heat exchanger to facilitate inspection within the 72-hour: time limit was scheduled for the third refueling outag The licensee concluded in the investigation of PIR 3-90-002 that valve SWP V696 was mispositioned because of the vague wer" ng on an attached caution tag which said "open for operability.- It-was reasoned that an operator, upon reading the tag, must have opened the valve all the way to ensure operability of the system. Accordingly, trouble reports were initiated ~ to reposition the throttle valves on the remaining heat exchangers and perform new flow measurements with a controlatron since it was reasoned that they may also be mispositione However,
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these actioqs were not vigorously pursued by operations personnel.and the valves were not repositioned. Additionally, following the January 4 event, the required action for differential pressure in the action range for the heat exchangers contained in SP3626.13 was modified from immediately declaring the heat exchanger inoperable to writing a PIR and have engineering' evaluate whether the heat exchanger is inoperabl Accordingly on May 9, 1990, when a high differential pressure was recorded on HVQ-ACUS 1B during a monthly surveillance, PIR-3-90-71 was-prepared. However, engineering personnel did.not properly diagnose the cause of the event in that when personnel noted the heat exchanger throttle valve was fully open, it was erroneously assumed that excessive flow was the cause for-the high differential pressur Further delaying review of the PIR was the unavailability of the controlatron which had been sent to the manufacturer for calibration on May 8, 1990, and was not returned'until June 8, 1990.. Therefore, the heat exchanger was left in the alert limit with questionable operability until June 14, 1990, when the surveillance was reperformed and flow was measured with a controlatro Licensee Corrective Actions and Inspector Assessment To prevent recurrence of the event, the licensee modified the required action contained in SP 3626.13 for ider.tification of heat exchanger differential pressure in the action range t the original requirement of immediately declaring the air con 6: 61on unit inoperable. Additionally, in licensee event reports-90-20-00 and 90-23-00, which were submitted to the NRC to . document the above events, the licensee committed.to visual inspection of the heat exchangers twice each operating cycl i The inspector noted that the increased heat exchanger inspections had already been planned to begin at the commencement of the third refueling cycle as part of the licensee response to generic letter 89-13 dated. January 25,. 199 The inspector noted that although the excessive tube-sheet fouling and heat exchanger damage made three of the four air conditioning units technically inoperable, the units were still , available to remove some ESF component heat had they been called upon in the event of an accident. Additionally, if high temperatures were detected in the ESF building during an accident, operators could have opened doors between ESF cubicles to improve ventilation. Finally, the normally running non-safety-related ventilation system which stops in the event of a containment depressurization actuation (CDA) or safety injection (SI) signal could have been started after jumpering * out various interlocks. Starting the non-safety-related i
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ventilation system, however, would require a non-vital power supply which could be lost. Additionally, it would violate the ; SLCRS boundary which could increase the~ offsite radiological dose. Therefore, although the safety-related ventilation system was degraded, it was still available-to perform its design function and compensatory actions could have been taken to mitigate the effects of the degraded air conditioning uni The root cause of these events was a deficient surveillance program combined'with poor operating judgemen The inspector determined that the licensee's corrective actions should be appropriate to prevent recurrence of this even However, it is noteworthy that plant management modified SP 3626.13 to allow continued heat exchanger operation even when availability of the equipment was questionable. Further, plant operations personnel removed the A emergency core cooling system from service while the operability of +ne "B" train support equipment had not been resolved. Such de' isions by. plant management and operations-personnel is an e> ample of a non-conservative decision regarding plant operation. A genera.lly conservative approach to plant : operation has been roted during_ previous NRC inspection Performance in this area will continue to be monitore Based upon review of this incident, per the policy in 10 CFR 2 Appendix C, no violation will be issued, because it was iden-tified by the licensee, it is a Severity Level IV violation, and corrective action is appropriate (50-423/90-10-01).
6.0 Engineering / Technical Support I 6.1 plant Design Modifications L 6. (Closed) Unresolved Item 50-423/84-04-02: Piping Seismic Analysis This item documented a concern that the seismica'ly-designed , ! piping inside the containment at Millstone 3 has not;been modelled.by coupling th_e piping and piping supports with the !- l attached steel structure in the dynamic piping analysis, > Rather, the piping system-has been analyzed as a. subsystem whereby the amplified building floor response spectra at the appropriate elevation within the containment structure have been used as input loadings -to the piping analysis model to determine l the dynamic piping response. Additional amplification or reduction of response due to the attached steel structure was not explicitly included in the analysis. Due to the theoretical nature of this concern, the item was referred to the-appropriate branch of the Office 'of Nuclear Reactor Regulation (NRR) for revie , l
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The NRR technical staff concluded in a July 12, 1990, memorandum that the standard review plan (SRP) sections 3.7.3 " Seismic ; System Analyses," and 3.9.2 " Dynamic Testing Analyses of : Subsystems, Components and Equipment," does not provide i guidelines for the inclusion of the additional response of i attached structures in the piping analysis. In general, it has l been the NRR staff practice not to require the dynamic coupling ! of piping systems to the a'ttached structural steel, other than ' pipe supports, except under unusual' conditions where the structural steel is deemed to be of a flexible configuration
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where the attached structure will have a significant-effect on the piping response. The criterion in SRP section 3.7.2.II.3 b, ;
"Decoupling Criteria for Subsystems when Performing Seismic Modeling," is applicable to decoupling subsystems and was not intended for decoupling subsystems (e.g., piping) from other 1 subsystems (e.g. , structural steel). i The issue of whether seismically d esigned piping systems should I be decoupled from the attached structural steel has been !
reviewed by the staf f in the past. The staff determined that , the f requency of attached steel structures is usually within a ' rigid range such that additional response from the steel structure onto the piping system need not~be considered in the analysis. Therefore, the piping system response is conservatively determined from the amplified building floor response spectra at the appropriate elevation within the- i containment structure. Consequently, the Millstone 3 piping systems are adequately designed for seismic -loadings and this issue is closed, j 7.0 Security l Selected aspects of site security, including site access contrsis, per-sonnel searches, personnel monitoring, placement of physical barriers, i compensatory measures, guard force staffing, and response to alarms and degraded conditions were cerified to be proper during inspection tour No inadequacies were note .0 Safety Assessment / Quality Verification !
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8.1 Committee Activities i The inspector attended meetings of the Plant Operations-Review Com- i mittee (PORC). The inspector observed that committee administrative- i requirements were met for the meetings, and that the committee discharged its functions in accordance with regulatory requirement The inspector observed a thorough-discussion of matters before the PORC and a good regard for safety in the issues under consideration by the committee. No inadequacies were identifie , U
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8.1.1 Audit of Lic.ensee Safety Evaluations Conducted Per 10 CFR 50.59 The inspector reviewed documentation of licensee activities that are subject to the requirements of-10 CFR 50.59, " Changes, tests and experiments," for the period of January 1,1989, to December 31, 1989. Specifically, the inspector sought to deter-mine if the licensee's safety evaluations were adequate to-determine whether any activities involved an "unreviewed safety question" as defined in 10 CFR 50.59(a)(2). .The documentation ' associated with the activities that were the subject of the , audit were selected from the summaries contained in the li-censee's 1989 annual report of changes, tests and experiments which was submitted to the NRC by letter dated February 21, 199 The licensee is permitted by plant procedure to use either-a safety evaluation form or a written safety evaluation. In some cases, the licensee uses both the form and a written narrativ For the purposes of the following, the inspector refers to both the form and.the written na,rrative as the " safety evaluation".
The following activities were the subject of the-audit:
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PDCR 3-86-040, " Spray Shield Around Pump Discharge" A pipe rupture at the Component Ccoling Pump (CCP) discharge could cause failure of the adjacent pump motor _ due to the high pressure fluid stream. The resulting failure would cause loss of all component cooling. The licensee's safety evaluation, which addressed seismic interactions and possible failure modes associated with the spray shield, was found to be very goo PDCR 3-86-063, " Add Time Annunciator on MP2B" E0P 35 FRZ.1 Step 7 requires that the operator verify con-I tainment spray / recirculation within 11 minutes following l ' receipt of a containment depressurization actuation (CDA) signal. The safety evaluation, although acceptable regarding the conclusion, had minimal detail and was based solely on the adequacy of the electrical isolation provided for the a.larm. Failure of the alarm was not considere For axample, the licensee did not consider in the safety evaluation what actions operators would perform-if the .; annunciator actuated prematurely or did not actuate at al However, the inspector noted in E0P 35 FR-Z.1 step 7, the licensee addressed this issue by requiring operators to verify recirculation spray flow was commenced 660 seconds into an accident if the annunciator has not illuminate pDCR 3-86-135, " Diesel Generator Piping Support Modifications"
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I Modifications to fuel and lube oil lines were needed t provide additional seismic restraint' and to prevent damage due to vibration. The safety evaluation was found'to be very good and addressed all aspects of the "unreviewed safety question" issue by directly addressing details of the modificat' ion- and the .FSA PDCR 3-86-334, "Repla'c ement of GE Series .SFF21 Relays in the EDG Control Circuit"- These underfrequency relays, which were replaced by GE Type SSF31 relays, were subject to false actuation due to noise signals. The licensee's safety evaluation of the relay replacement was acceptabl .
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PDCR 3-88-008, " Installation of AMSAC System to Comply with 10'CFR 50.62" Safety evaluation ISE/MP3-88-123 was very good ;in that- it contained considerable detail concerning the safety-impileation of operation or failure of the AMSAC syste PDCR 3-88-014, "Litton'Veam Connector Replacement"- A total of 31 Litton Veam electrical connectors were replaced with various alternate types due to electrical i environmental qualification (EEQ) problems- The associated safety evaluation was acceptabl PDCR 3-89-017, "ASCO Solenoid Valve Replacement" The EEQ lifetime of these valves was being decreased due to elevated internal temperature. The replacement valve has exterior cable termination which decreases the internal temperatur The safety evaluation was found to.be (cceptabl PDCE 3-88-158, " Containment Sump Level ' Instrument" A capacitance level instrument was replaced by a dis-placement level instrument as a result of calibration , problems with the former. The safety evaluation was'found to be acceptable.
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Change to Procedure OP 3338A, " Solid Waste" The procedure allows flushing of spent resin transfer lines and the pump filter. The safety evaluation was found to be ) acceptabl J-LL-B 3-89-018, " Temporary 120 VAC"
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A temporary 120 VAC power supply was provided during an "A" train outage to prevent actuation of the radiation monitor and. subsequent isolation of the control building ventila-tion syste The safety evaluation was very good in that it addressed the_ continued-operability of the control i building isolation capability with use of the temporary power suppl J-L10B 3-89-50, " Defeat of Automatic Trip" i The automatic trip on low pressurizer level was defeated to allow investigation and retest of RCS*H18. The safety i evaluation was marginally acceptable due to a lack of detail. Specifically, in using the safety analysis form, a number of entries appeared as "N/A" with no explanatio , In this situation, explanations should have been give ' However, no unreviewed safety question was noted by the e inspecto Set Point Change 3-89.-00B, " Pressurizer Level Control Program Change" The pressurizer level . control program was changed to reflect a reevaluation of level measurement errors. The safety evaluation was very good and described the effect of pressurizer. level on various accident In summary, the evaluations reviewed supported the licensee's
"no unreviewed safety question"' determination in each case, The quality of the documentation for the' safety' evaluations,:
however, was uneven. Several answers to questions asked in the : safety evaluation forms were not completely answere ~
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Specifically, although the engineer would state that a modification was acceptable, no' explanation would be given to support the assertion. The-licensee should assure that:each safety evaluation contains adequate details to determine the effect of the proposed change on the "unreviewed safety question" criteria of CFR 50.5 .2 periodic Reports Upon receipt, periodic reports submitted pursuant to technical speci-fications were reviewed. -This review verified that the reported in-formation was valid and included the required NRC data. The inspector also ascertained whether any reported information should be classirlea as ari abnormal occurrence. The following-report was reviewed:
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June Monthly Operating Report No significant observations were mad ,
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l'. l l4 23 .3 Licensee Event Report Review 1 Licensee Event Reports (LERs) submitted during the report p'triod were ; reviewed to assess LER activity, ad quacy of corrective actions, com- ' pliance with 10 CFR 50.73 reportin, 'quirements, and determination of generic implications if further . ion was required. Selected i corrective actions were required for impi..ation and thoroughnes The LERs reviewed were: l
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LERs 90-13-00 through 90-20-00 and LER 90-22-00 These LERs are discussed belo . LER 90-13-00, Manual Reactor Trip Due to Loss of Condenser Vacuum This LER reported an April 16, 1990 manual reactor trip vhich operators initiated when the B circulating water pump automati-cally tripped due to high differential pressure across its ,
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travelling screens. The details of this event were reported in -! inspection report 50-423/90-0 * Four licensee corrective actions were stated as having been i taken in the LER. (1) The trash racks high differential level alarm point was lowered from 15 to 6 inches. (2) Personnel were instructed to closely monitor trash rack water levels and clean the racks before differential pressure levels exceeded 4 inches. _(3) The procedure which governs plant response'to , severe weather was revised to require each circulating water
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i pump to supply only the associated waterbox if severe weather is i predicte This would ensure flow across the screen is limited to 100 percent and thereby reduce potential for excessive sea-weed loading. (4)' The rake tips were redesigned to extend on i inch between the rack bars. The modification was expected to improve rake cleaning by preventing seaweed from being pushed through the rack The inspector noted 'that _the licensee lowered -the trash rake < differential alarm setpoint and personnel have been instructed i to perform trash raking operations when. differential pressure begins to increase across the trash rakes. The licensee had i
also completed modifications to the trash rake. The inspector noted however, that as of August 1,1990, the licensee had not yet modified procedure SP 3665.2, Intake Structure Detarmina- ' tion, which governs the plant response to severe wes sher as stated in the LER. The inspector discussed this finding with an assistant operations supervisor who indicated that procedure SP 3665.2 would be modifie The incorrect information contained in LER 90-13-00 apparently was the result of inadequate verification of completed actions by individuals respohsible for LER preparation and by the applicable review c?ganization .
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According to. licensee management , when the reactor trip was discussed at a plant operating r.' iew committee meeting, opera-tions personnel stated that procedurt SP 3665.2 would be revised prior to submittal of the LER. The ngineer who prepared the LER relied on that statement and prepared the LER accordingl However, operations personnel failed to revise the procedure because of higher priority items. This oversight was not de-tected by unit and station managerent when the LER was issue The inspector noted that an incorrect report (LER 89-09) was also submitted on June 12, 1989. When that LER was submitted to the NRC, it incorrectly stated that procedure SP 3451N21 rod drop time test had been revised to prevent recurrence of the event. Subsequent inspector follow 6p of the LER revealed that-the procedure had net been updated ustil December 1, 1889. .That discovery was documented in inspection report 50-423/89-21 as an unresolved item 89-21-05, and the item was later closed in inspection report 50-423/90 04 after a corrected LER was sub-mitted and a satisfactory explanation was given. Recurrence of this matter reveals that the licensee's program to ensure the accuracy of reported information is deficient. The applicable , review organization responsible for LER preparation did not verify that corrective actions had been completed as stated in t'e LER prior to submittal to the NRC. The failure to correctly report the actions completed for LER 90-13-00'is a violation of 10 CFR 50.73(b)(1) and 10 CFR 50.9(a) (50-423/90-10-02).
8.3.2 LER 90-14-00 Manual Reactor Triy J ue to Loss of Condenser Vacuum This LER documented a May 19, 1990 reactor trip which operators
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initiated when the B circulating water pump automatically tripped due to 'igh differential presture across its travelling scree .
>< fics of this event were discussed in insp&ction report 50 123/90-0 Licensee corrective actions to prevent rtcurrem cf this ever t were to modify SP 3665.2 intake structure determ :ations to allow a faster downpower rate when inclement weather occur The previeus downpower rate allowed by the procedure was .5 y percent to 1 percent per minute. The revised procedure now
. allows the maximum downpower rate of 5 percent per minut Operations personnel were also instructed.to evaluate intake conditions more frequently during periods of inclement weathe The inspector verified that procedure SP 3665.2 was revised to include the faster downpower rate and personnel were sensitized of the need to evaluate the conditions at the intake. structure duHet; periods of inclement weather. The inspector noted that as a result of previous' intake system problems identified, the licensee will perform several radifications by the structur They will be evaluated during future resident .nspections. The ' inspector had no further question .
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8.3.3 LER 90-15-00, Feedwater Isolation When Opening Main Steam IsolatiorTTa,lves This LER documented an automatic feedwater isolation (FWI) which-occurred on May 12, 1990 when operators did not use a procedure to open the main steam isolation valves (MSIVs). This event was discussed in inspection report 50-423/90-08 and resulted in a notice of violation being issued. Licensee corrective action consisted of counseling the operators who performed the evolution and revising the main steam operating procedure sequence of steps so that the operator reads the notes and precautions prior to opening the MSIV The inspector verif_ied that. the niain steam operating procedure OP 3316A was revised. The effectiveness of the licensee cor-rective actions regarding operator adherence to procedures will be evaluated in future resident inspection . LER 90-16-00, B Steam Generator low-Low Actuation
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This event occurred on May 13, 1990, and was' discussed in: inspection _ report 50-423/90-08. Licensee action to prevent returrence was to revise procedure OP 3316C to require steam generator level transmitters to be equalized at the time they are isolate The inspector reviewed OP 3316C Steam Generator Blowdown and verified that the procedure was revised as stated. The in-spector considered the licensee response of this event to.be correct aid corrective actions taken to prevent recurrence to be satisfactory and had no further question .3.5 LER 90-17-00, Both Trains of Safety Injection Inoperable
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Fe~cause of Personne IError This event occurred on May 12, 1990, when operators used an incorrect procedure to fill safety injection accumulators and failed to complete the actions of that procedure. This event was di= cussed in inspection report 50-423/90-08 and resulted in a not .e of violation being issue Licensee corrective actions consisted of (1) counseling the operators who were involved in the event; (2) revising guidance on the use of a dedicated operator was provided to all shifts; and (3) modifying the safety injection accumulator fill proce- i dure to make procedure restrictions more visible to the operator.- ' The inspector verified that OP 3310B was revised and suitable interim guidance concerning use of a dedicated operator was provided to operators via a " night crder." The effectiveness of ,
the licensee corrective actions regarding operator use and ad-herence to procedures will be evaluated in future resident in-spection _
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8.3.6 _L,ER 90-18-00, Improperly Established Fire Watch ; This LER documented a discovery on June 2,1990, of a failure to l correctly post a fire watch after fire rated assemblies had been declared inoperable on June 1, 1990. This event was a violation of technical specification 3.7.33 which requires that compen-satory ..tions be taken within one hour if the assemblies are
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l declared inoperabl The cause of this event was personnel error, . The shift super-visor (SS) did not provide sufficient guidance to a primary' , equipment. operator (PEO) on the proper placement of fire watch sneets. Consequently, the PE0 placed the fire watch sheets in .
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the A and 8 recirculation spray cubicles rather than the engi-neered safety features sump and a recirculation spray system .; cubicl i Corrective actions taken were to post the required fire watch , and counsel the SS on the importance of verifying communications ! to plant personne .
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The inspector agrees with the licensee assessment and reporting of this even No violation will be issued for this discovery, per the policy in 10 CFR 2 Appendix.C, since the' licensee-identified item had minor safety significance, the item was-reported as required, and corrective. actions were appropriate to : l prevent recurrence (50-423/90-10-03). i
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8. LER 90-1s-00, Reactor Trip Due to Dropped Control Rod _
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i This event occurred on June 6, 1990, and was-documented in ; inspection report 50-423/90-0 Inspector followup of this event included observation of licensee troubleshooting operations, examination of the defective control rod cable, and review of the post-trip sequence of events. A supplemental report of this event.will be: ; submitted by the licensee by December 28, 1990, and.w111 be-reviewed by the inspector at -that time for adequacy.. The ' t inspector has no further questions on th's issu , $ . . 8. , LER 90-20-00 and LER 90-23-00, Both Trains of Engineered r Safety Features Equipment Inoperable i Both licensee event reports are previously discussed in this inspection report and each concerns 'the inoperability of air conditioning units for engineered safety features equipmen ,
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o ) s, 27 l s ! I 8.3.9 LER 90-22-00 Missed Hourly Fire Watch j On June 18, 1990, with the plant at 80 percent of rated power, the shift supervisor (SS) discovered that an hourly firewatch i had not been established in battery no. 4 inventor room after . its associated fire detection zcne panel had been declared l inoperable on June 16. The SS after reviewing procedures OP : 3250.41B, " Removing Fire Detection From Service," and OP 33410, I
" Fire Detection Protection and Control," established hourly fire l watch patrols as required by the action statement of technical l specification (TS) 3.3.3.7.b. However, the procedures for !
establishing fire watch patrols were inadequate in that they f ailed to specify. the battery inverter rooms as a separate zone, , Rather, the procedures stated that a fire watch should be i established in the A and B battery rooms een the. zone panel was * removed from service. A correct pictorial. description of the , areas served by the fire protection zone panel was contained in OP 334]D; however, it was not used by the SS when determining ' fire watch location ,
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The corrective actions contained in the LER included immediately posting the required fire watch, and modifying procedures OP 33410 and 3250.418 to identify the-invertor rooms as separate fire watch location . Inspector followup of this event consisted of review of the applicable procedures, technical specifications and interviews with licensee personnel. The inspector verified that the pro-cedures were modified as stated in the LER. The inspector noted
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that the licensee investigation of this LER identified that ' discrepancy exists between the plant TS 3.3.3.7 and the fire protection evaluation report. Specifically, the fire protection
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evaluation report lis.s the battery invertor room as a separate ; zone where the plant TS does not.- Through discussions with engineers, the plant procedures'for establishing fire watches-were based on the plant technical sp'ecifications. .The inspector, t af ter completing review of this event, considers the licensee corrective actions to be appropr. ate and no violation will be i issued for this discovery, per the policy in 10 CFR 2, Appendix C, since the licensee-identified item had minor safety signifi- ! cance, the. item was reported as required, and corrective actions were appropriate to prevent recurrence (50-423/90-10-04).
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8.4 Quality Assurance issues Closed , 8. (Closed) Unresolved Item 50-423/88-15-01: Licensee Shelf Life Controls of Condensate polishing Resins : This item documented NRC findings that Quality Assurance (QA) category I resin stored in the condensate polishing facility (CPF) was not assigned a shelf life expiration date. This was ! contrary to ACP 4.06B, " Degradable Material Control Program," i which states that resins are degradable material and shelf life ! controls are require Further, the. purchase orders which procured the resin specified improper controls - level C vice level B. Level C controls could subject the resin to damaging environmental conditions such as freezin In response to the inspector's findings, the licensee conducted ; a self-assessment of the degradable materials control progra The review consisted of (1) performing a random sample of ware-house items to ensure shelf life tags were installed; (2) sampling : the generic degradable ite4ns list to ensure degradable materials had been entered into the shelf life controls program, and- "
(3) reviewing procurement requisitions to ensure shelf life controls were specified where require <
Based upon results of-the audit, the licensee concluded that the inspector's previous findings were not a generic issue. The improper shelf life controls and purchase order specifications were attributed to personnel oversight. 'Specifically, of 632 warehouse items sampled during the audit, fourteen were dis-covered without shelf life tags- All fourteen items had been
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ordered prior to implementation of the degradable material con-trols program. A review of 75 items in the generic degradable items list verified that the items were incorporated in the
- degradable material program. A review of 482 purchase requisi-tions, verified that appropriate shelf life controls were ap-
' plied where required. Two degradable items were found without tags, and both deficiencies were correcte Licensee actions taken since the self-assessment to further ' improve the shelf life program included rewriting store > procedure STP 1075 to provide step-by-step instructions tu stockholders on the receipt and inspection of shelf life ' materials. Stores supervisory personnel are now required on a daily basis to review purchase orders at the point of receipt, and material issue forms at the point of issu .t s
- The inspector noted that resins are now stored in a controlled l location - warehouse #6 vice the previous CPF and Great Neck warehouse storage locations. Warehouse #6 is located outside of C
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the protecte,d area in a butler style building surrou : led by asphalt paving. The inspector toured the warehouse and verified that it met the requirements for level B storage of resin per ANSI N452.2 - clean and dry with provisions for temperature control. The resins were stored on wooden pallets. located on metal rack Lot number 932640 was inspected and found.to be in good condition with a shelf life expiration date of May 23, 1991. This date corresponded to the resin certificate of conformanc The inspector reviewed a resin purchase order and verified that appropriate shelf life information was requeste Through conversations with stores personnel, the inspector;was informed that the resin which was originally found to be.im-properly labeled was received on May 16,'1988, and used by January 21, 1989 - well within-the expected two year shelf life of the resi Based upon review of the licensee's shelf life program, the inspector concluded the licensee has adequate measures in place to ensure Q/A resins are properly purchased, received and, stored. Therefore, this item is close , 8.5 Management Meetings Periodic meetings were held with station management to discuss in-spection findings during the inspection period. A summary of findings was also discussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspec-tion. No written material.was given to the licensee during the inspection perio . l
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