IR 05000346/1997009
| ML20217G892 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 10/01/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20217G870 | List: |
| References | |
| 50-346-97-09, 50-346-97-9, NUDOCS 9710140277 | |
| Download: ML20217G892 (19) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION lil i
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Docket No: 50 346 i License No: NPF 3 .
Report No: 50 346/97009(DRP)
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Licensee: Toledo Edison Company l
Facility: Davis Besse Nuclear Power Station Location: 5503 N. State Route 2 Oak Harbor, OH 43449
Dates: July 7 August 18,1997 Inspectors: S. Stasek, Senior Resident inspector K. Zellers, Resident inspector ;
Approved by: Geoffrey C. Wright, Acting Branch Chief Reactor Projects Branch 4 l-
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9710140277 971001 PDR -ADOCK 05000346 PM
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EXECUTIVE SUMMARY Davis Besse Nuclear Power Station NRC Inspection Report 50,340/97009(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6 week period of resident inspectio Oparations
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Material condition of engineered safety features and important to safety plant systems was excellent (Section 02.1),
a Communi':ations and documentation associated with a Limiting Conditions for Operation action that was required in response to an inoperable Reactor Protection System channel was inadequate (Section 01.2),
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i Thr'" Conduct of Operations * procedure granted the shift supervisor unilateral authority to allow procedural steps to be performed out of order. The NRC identified that this authority did not conform to the requirements of Technical Specification 6.5.3.1.b in that for a procedure change, a second review and approval by another member of plant management staff was not specified in the procedure (Section 08.1).
Maintenance
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Maintenance and surveillance activities observed or otherwise reviewed during the inspection period were conducted in accordance with plant procedures and applicable regulatory requirements (Section M1.1).
Engineering
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Leakage integrity of the Component Cooling Water system was not verified nor were applicable acceptance criteria established for leakage between the essentlal and non-essential portions of the system. At the conclusion of the inspection period,
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engineering personnel were evaluating the need for additionalintegrated system leakage rate testing (Section E3.1).
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Inadequate interim corrective actions were established to address a postulated worst case Circulating Water system linebreak. Although an analysis indicated that operators would have insufficient time to respond to the break and subsequent flooding conditions, no actions were taken to provide additional guidance for operator response or to extend the required operator response time. This situation was determ'ined to be a violation of 10 CFR Part 50, Appendix B, Criteria XV " Corrective Actions" (Section E8.4),
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Plant personnel exhibited satisfactory adherence to radiation nrotection program requirements (Section R1).
The inspectors were concerned that, given the normal duties of the assistant shift supervisor, the management decision to designate the control room assistant shift supervisor as the fire watch brigade captain, could result in delays in manning the j fire brigade (Section F8.1).
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Report _Datalla
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Summary nf.Riant_ Status The unit w as operated at nominally full power throughout the inspection perio L on.,ations 1 .
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01 Conduct of Operations 01.1 Ganatal cammanta (71707)
The inspectors observed control room operators during the conduct of shift activities; I walked down control room panels; reviewed logs, equipment clearances (tagouts),
and Technical Specification (TS) Limiting Conditions for Operation (LCO); and
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- interviewed _ operations personnel throughout the inspection period. Shift turnovers and shift briefs were properly conducted, with one exception (see Section 01.2). .
Procedure adherence was good overallincluding operators' usage of alarm response procedures. Operator rounds were appropriately conducted in accordance with plant procedure .2 implamentatlartof_IS. Action.Statamcata_Whan.Raactor_ErotectiortSystemlRES)
ChannaL2_Was Daclared. inoperable
--- 3 . _ inspectinn Sr nna (717Dh On August 7, channel 2 of the RPS was declared inoperable due to problems ic'entified with the input signal from NI 5 (excore nuclear instrument 5). The inspectors reviewed operations personnel followup actions relating to the applicable TS LCO entries, Observatlana_andlindines The inspectors noted that Action #2 associated with TS Table 3.31, " Reactor
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Protection System Instrumentation," was applicable and specified two followup actions. The first action required either tripping RPS Channel 2 or placing the channelin manual bypass within one hour of declaring the channelinoperabl Operators elected to place the channel in manual bypass with that action appropriately documented in the control room lo The second LCO action required that the licensee verify at least once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that the reactor core quadrant power tilt (OPT) was within acceptable limits. The
! inspectors identified, however, that the licensee was not formally tracking the verification that OPT was within limits nor were verification activities being documented. No associated information appeared in the control room log nor were the control room " white boards" used to post the necessary information as expecte .._ .
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In addition, the required OPT ntification actions were not communicated to the day i shift operating crew during shift turnove The inspectors determined that pertinent core parameters, including OPT data, were
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available to the control room operators on a real time basis via the process computer, and although not formally tracked, it was operations management's expectaCon that control room operators frequen ly monitor those core parameters to verify they were within accepteblo limits. The process computer was designed to automatically update reactor core informi.tlon every six minutes and operators routinely reviewed the information on the monitors to ensure that core parameters remained within acceptable limits. The int.pectors have observed that control roorn operators routinely check the process computer read-outs. The inspectors also verified that the process computer will alarm if OPT data is out of specification. The inspectors also reviewed a hwdcopy printout of OPT for the time frame in question and verified that OPT had remained withi.n acceptable limits. As such, the inspectors ascertained that quadrant power tilt had not unknowingly varied from acceptable limit No violation of NRC requirements was identified, however, plant management i
indicated that the tracking of LCO action statement requirements should have been hand!cd formally and that associated information should have been communicated to subsequent operating shifts via the turnover process, in addition, if the process cornputer had failed, OPT verification activities might not have been performed within the applicable timeclock requirements. The licensee initiated Potential Condition Adverse to Quality Report 97-1064 to address this matte Conclusions Inter shift and intra shift communications and documentation associated with LCL actions required to be taken in response to Reactor Protection System channel 2 inoperability were inadequat Operational Status of Facilities and Equipment 02.1 SystemEalkdownsl717D2)
The inspectors walked down the accessible portions of the following engineered safety features and important to-safety systems during the inspection period:
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Station Blackout Diesel Generator Decay Heat / Low Pressure Injection System - Trains 1 and 2
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Hig5 Pressure injection System - Trains 1 and 2
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Service Water System
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Component Cooling Water Room Ventilation System
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Auxiliary Feedwater i Train 2 -
Motor Driven _ Feed Pump :
- No substantive concerns were identified as a result of the walkdowns. System lineups and ma}or flowpaths were verified to be consistent with plant procedures / drawings and the Updated Safety Analysis Report. Pump / motor fluid levels were within their normal bands. Vibration and temperatures of running equipment were normal.' Only very minor oil and fluid leaks were noted on occasio _
Local anct remote controllers were properly positioned and attendant instrumentation appeared to be functioning correctly. Equipment material condition was excellent in -
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' 08 Miscellaneous Operations issues (92700)
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d8.1 rin..at unr..niv a h m mn-sanienna-01(DRP)): Control of temporary changes to procedures. During the inspection period, the inspectors reviewed plant administrative procedure DB-OP-00000, " Conduct of Operations " and determined that with one exception, DB-OP.00000 conformed to the requirements of Technical Specifications 6.8.4 and 6.5.3.1 relating to plant procedure preparation and us The one exception involved Section 6.8.3 of DB OP-00000 which allowed the shift supervisor to authorize,if needed, the performance of procedural steps out of the
_ order specified by a sysiem operating procedure as long as the intent of the procedure was not compromised. The' shift supervisor could take this action unilaterally without the review and approval of a second member of plant management staff. However, the inspectors noted that Technical Specification 6.5.3.1.b requires that procedure changes which do not change the intent of the procedu e be approved by at least two members of the plant management staff, at
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least one of whom holds a senior reactor operator's licens : During discussions with the inspecton,, operations management indicated that-Section 6.8.3 of DB OP-00000 was not routinely'used, and did not allow, the shift supervisor to make changes to the procedure itself but simply allowed him to implement procedure steps in a different sequence than that specified by the procedure. The inspectors disagreed with the licensee position that performing the steps out of-order did not constitute a procedure change; the licensee indicated only written changes to documents were procedure changes. Administrative procedure DB OP-00000 was inappropriate because it allowed the shift supervisor to unilaterally authorize a procedure change without the review and approval of a second member of plant management staff, and is considered a violation of TS 6.5.3. (50 346/97009-01(DRP)).
..08.2 LClosedLLEEL50.346196:00&00 Switchyard.CircuillnoperableDue.202Witchyard
' Breaker _ Alignment. This LER described a licensee identified equipment configuration Jwhere a complete loss of offsite power could potentially occur if one of three incoming 345 kilovolt (kV) transmission lines to the plant switchyard was out-of-service ano an additional specified single failure were to occur. The licensee-previously thought that the required redundancy for offsite power would still be
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provided with one of the three incoming lines out-of service. However, the licensee identified that the protective relaying in the switchyard was configured such that if one incoming line should fail, the protective relaying would clear the fault by opening
- the associated breaker for that incoming line as well as lockout the circuits adjacent to the faiteu breaker. In certain cases, this would result in opening of an incoming breaker for a second incoming circuit, if this single failure were to occur with the third circuit already out of service (e.g., for maintenance), a complete loss of offsite power would resul The apparent cause of this unrecognized vulnerability was a misunderstanding of the design and operational requirements for certain switchyard compenents. Plant personnel reviewed the unit log for the previous year and identified four other similar switchyard configurations where one circuit between the offsite transmission network and the onsite class 1E A.C. electrical power distribution system was inoperable. In three of the four cases, normal switchyard configuration was restored within the required TS 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed outage time, in one case, however, one switchyard breaker was isolated for a period of approximately 12 days to perform preventive maintenance. Because of the ,
connection between the remaining 8ines, two independent offsite power supplies were not available. Both emergency diesel generators, as well as the station blackout diesel generator, were operable during that timeframe, and could have provided necessary emergency electrical power if neede Subsequently, the licensee provided additional operator guidance for entering Technical Specification LCOs related to switchyard work. Appropriate TS LCO time-clocks were to be applied whenever breaker work as described above was l performed in addition, the licensee planned on reviewing the Updated Safety Analysis Report revising appropriate sections to clarify the description of switchyard configurations and redt.ndancy of offsite sources. The licensee planned on incorporating these changes in the Updated Safety Analysis Report during the next routine updat TS 3.8.1.1 specifies that at least two offsite A.C. power sources be available to the switchyard or entry into a 72-hour LCO would be required. The switchyard configured where redundancy of incoming power was less than required by TS for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />,is considered a violation of TS 3.8.1.1 However, since this violation was licensee identified, adequate corrective actions were taken, and the criteria for enforcement discretion were otherwise met, this matter is being treated as a Non Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50 346/97009-02(DRP)).
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LL_ Maintenance M1 Conduct of Maintenance M1.1 Maintenanca.and_SurveillanenActivitiesl61226)(62702)
The following mainter.9nce and surveillance testing activities were observed or reviewed during the inspection period:
MWO 7-96-1104 04 Calibrate LT 1525D, SFAS ISafety Features Actuation System] Channel 4 BWST IBorated Water Storage Tank)
Level Transmitter MWO 7 961042 01- Remove and Replace (EDG) Brush Holder Block MWO 3 97 5128-01 Replace Agastat Time Delay Relay K005-01 TD4/EDG1 (Emergency Diesel Generator)
MWO 3-97 0725-01 EDG [ Emergency Diesel Generator) #1 Electrical Cleanliness Check MWO 3-97 0723-01 EDG #124-Month PM [ preventive maintenancel DB-DP-03160 (Rev 03) #2 AFP lauxiliary feedpunip) Quarterly DB SP-03137 (Rev 03) Decay Heat Pump 2 Quarterly Pump and Valve Test DB SP-03219 (Rev 02) HPl(High Pressure injection] Pump 2 Quarterly Pump and Valve Test The inspectors noted good personnel adherence to test procedures during the performance of surveillance testing activities. Pump, turbine, and motor bearing oil levels appeared to be satisfactory. Operators were observed to closely monitor equipment performance while under test conditions. Technical Specification LCOs were entered as required. Test deficiencies were identified, documented, and resolved satisfactorily. Tested systems performed as described in the Updated Safety Analysis Report Cognizant operations and engineering personnel collected, analyzed, and reviewed pertinent in-service testing data in a timely manne Maintenance activities reviewed during the inspection were conducted in accordance with approved plant procedures and programs. The inspectors noted that level transmitter calibration data packages sampled for review correctly compensated for head correction factors, instruments were calibrated within their required range Maintenance craft personnel employed appropriate foreign material exclusion controls. Burn perrnits were posted with appropriate fire extinguisher equipment available when required. Electricians / instrumentation and control technicians utilized lifted wire logs appropriately. Good coordination of planning and support activities were note M8 Miscellaneous Maintenance issues (92902)
M8.1 (CinsedLunresolved Item _(50-346196002-01(DRPJ): Safety Features Actuation System channelinoperability and timeliness of taking LCO actions during certain surveillance testing activities. This matter involved a concern that Safety Features Actuation System channels that were rendered inoperable during testing were not
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placed in the TS required tripped condition untillust prior to the associated one-hour LCO timeclock expirin Subsequently, operations management expectations that LCO actions were not to be delayed until the "last minute * but were to be implemented in a controlled, conservative manner, were discussed with the operating crews. No violation of NRC requirements was identified, Operator performance in this area improved with the inspectors noting no additional examples where LCO actions _were delayed to a point where their implementation would have been rushed due to impending expiration of an LCO timecloc M8.2 (ClosedLVinIMinn (sn-346L9 Bon?.10(nRP)}: The High Pressure inlection system was not vented at its discharge line high points in accordance with Technical
~ Specification 4.5.2.b. This matter involved a Severity Level ill violation that was issued on June 13,199 Following identification that the piping had not been completely vented per the TS, the licensee verified that the affected section of piping was water filled and an
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emergency license amendment was requested to allow the licensee not to perform l
l the applicable TS surveillance requirement untilinstallation of a vent line could be completeo during the next refueling ovoge. During the tenth refueling outage, which ended on June 2,1996, the subject vent line was installed and appropriate procedural and drawing changes were made to reflect the installation. Further, actions were also taken to ensure that personnel adequately reviewed similar issue Subsequently, the licensee reviewed the Updated Safety Analysis Report in detail to confirm it accurately reflected the current plant configuration and venting practice MB.3- (Cinsed) inenetinn Fnlinwon l'am inn nasLq600R.n?(DRP)): Reader / worker practices. The Superintendent, Instrumentation and Controls / Electrical Maintenance agreed that the poor reader / worker practices noted by the NRC were not to his expectations. Subsequently, those expectations were communicated in keeping with his maintenance craft. No further instances of poor reader / worker piactices were noted by the inspectors, lit. Fnginaaring E3 Engineering Procedures and Documentation E ComponenLCooling. Water _taventory_following.a. Design Racie Reismic. Event InspectiorLScopa.(325 SAL The inspectors performed a followup review of a licensee identified issue relating to a Component Cooling Water (CCW) expansion tank sample valve lineup concern documented in Potential Condition Adverse to Quality Report (PCAQR)97-072 e1w '
, , Observations 2nd.Eindings The CCW system was designed to provide cooling water to non-essential reactor auxiliaries during normal station operation, and essential emergency core cooling systems during normal station operation and accident conditions. The non-essential portions of the system were not designed to withstand a design basis seismic even In order to preserve the water inventory of the normally connected essential portions of the system, boundary valves between the essential and non essential portions of the system were designed to close in response to decreasing CCW expansion tank levels which would occur in the event of a rupture of the non-essential portions of the syste ~
The inspectors determined that no CCW system testing was being performed to ensure CCW inventory levels would be satisfactorily maintained after a design basis seismic event. Additionally, no quantifiable CCW system leak rate acceptance criteria had been established.
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I At the end of the inspection period, as a result of inspector questioning, the licensee was planning to perform CCW system leak rate testing and was in the process of determining appropriate leak rate acceptance criteria. The licensee initially determined that a plant outage would be required to perform the leak rate testin The inspectors had no immediate concem relating to CCW operability for several reasons: 1) CCW was a clean water system utilizing demineralized water which limited the amount of corrosion in the system and therefore limited degradation to va!ve stems and seats 2) there was a lack of evidence that the safety related part of the system had previously experienced a loss of inventory due to boundary valve leakage; 3) a relatively large (67 gpm for each train) safety-related makeup capability from the Service Water system was available and 4), the CCW system boundary valves were designed for leak isolation capabilitie This issue was first identified by plant engineering personnel on October 22,1996, as documented in PCAOR 96-1357 which referred to an NRC inspection (reference inspection Report 50-440/96008) that had been conducted at the Perry plant during which a concern with the classification of boundary valves in an essential closed ooling water system had been identified. These boundary valves were classified as American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI Category B valves (which did not require leak rate testing), however, it stated that leakage needed to be limited in order to conserve essential closed cooling water inventory. The PCAOR added that a similar concern existed with several Davis Sesse CCW valve Based on an initial assessment of the PCAOR, completed November 5,1996, the licensee determined that no additionalleak rate testing was required, but that an in-service testing program review was required. Remedial action was originally assigned on January 14,1997, and was due to be completed by April 18,199 The assigned actions included performing a review of all plant valves listed as ASME Boiler and Pressure Vessel Code Section XI Category B and C valves that may require
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leak rate testing and documenting the results, as well as updating the in service testing pump and valve program based on the results. Subsequently, the due date was extended to October 31,199 Subsequent to the inspection end date, the licensee estab!ished an interim leak rate criteria of 20 gallons per minute and intends on performing a leak rate test during the next refueling outage, Conclusions Although the inspectors had no immediate operability concern relating to the ability of the CCW system to maintain its inventory following a design basis seismic event, no CCW inventory testing had been done and no system leak rate acceptance criteria had been established. Further review to evaluate the licensee's corrective action efforts and to determine if any regulatory requirements were violated was in process at the end of the inspection period. Pending completion of inspector review to determine whether, as a minimum,10 CFR Part 50, Appendix General Design Criteria 46 is applicable to this matter, this is an unresolved item (50 346/97009-03(DRP)). ,
E8 Miscellaneous Engineering issues (92902)
E LClosed) i FR 602461924)D4-On, RpactoLCoolant RumpAintor nii Piping Not
&atecteditomleakage.As11equired.2pr 10 CFR RO Appendix B. This LER involved licensee identification that portions of oil piping for reactor coolant pump motors were located outside of the Appendix R required oil collection system enclosure. The involved sections of piping included: 1) the source connection for three pressure switches,2) a pressure gauge for the lift oil pump system, and 3) a portion of piping for the lower bearing remote oil fill connections. Based on an evaluation of the as-found configuration, the licensee concluded that the issue had limited safety significance because the operating pressures were minimal and/or the associated piping was not pressurized during normal operation. The licensee subsequently completed a modification to the oil collection system for each reactor coolant pump to enclose the subject piping sections. The modification was completed in May 199 E8.2 (ClosedLViolatiord50a46196014-04!DBP.J): Failure to install radiation monitoring in the new fuel storage area that was capable of alarming in response to a postulated accidental criticality. The licensee submitted a request for exemption from 10 CFR 70.24a, dated January 24,1997, in re.sponse to a request for additional information, the licensee submitted an additional response dated May 28,1997. Since this matter is currently under review by NRC headquarters, and will be resolved through the applicable processes therein, this matter is considered closed. The licensee has agreed to install monitors or obtain an exemption from the regulations prior to handling nsw fuel. No new fuelis currently on site,
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E8.3 (Closed)EnresolvedJtem.150-3461980lO:0MDBPJ): Placement of portable equipment in the control room without adequate engineering evaluation. The subject
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room to improve overall air quality.' Both units were subsequently removed from the .
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control room envelope pending completion of additional engineering evaluatio Engineering personnel determined that there would be no adverse effects due to placing the air filter units in the specified control room locatioas. The air purifiers were then returned to the control roo Subsequently, control room operators determined that computer equipment had also been installed in the control room without appropriate engineering evaluation. A potential condition adverse to quality report was initiated to track resolution of this issue. However, no adverse effects from the computer equipment were apparen This matter is close E8.4 (Closed)EnresolvedJtem_(50:348192008-05(DRPJ): Analysis for postulated Circulating Water system pipe break. In response to the probabilistic safety analysis that was issued in May 1996, the licensee initiated Modification 95-0057 to install a series of level switches in the main condenser pit. Installation of the subject modification was completed during this inspection period. As documented in inspection Report 50 346/90008, prior to the installation of the switches, the consequences of a postulated circulating water system pipe break included severe (
flooding of the turbine building such that loss of all feedwater including auxiliary feedwater could result, in the worst case, a loss of all feedwater would occur within approximately six minutes of the initiating event. As such, the probabilistic safety assessment report indicated that until the subject modification was installed, operators would not have sufficient time to mitigate this acciden The licensee had taken substantialinterim compensatory measures to reduce the probability of this event occurring by assuring that the material condition of the Circulating Water piping was satisfactory. However, the interim compensatory measures taken to reduce the consequences of a Circulating Water system linebreak, should it have occurred, only included: 1) placement of an operator near the condenser pit area during pump starts and stops, and 2) general training of the operating shifts concerning the subject accident sequence. No efforts were documented that focused on providing operators additional time to respond, nor was specific procedural guidance provided to the operators in addition to that already identified in the associated abnormal procedure. Following discussions with the NRC, additionalinterim compensatory measures were instituted to improve operator mitigation capabilities. Specifically, the turbirio building main roll-up door was required to be opened at least three feet to allow additional egress pathways for postulated flooding in the turbine building. According to the probabilistic safety analysis report, this would double the time needed to cause a loss of all feedwater (from 6 minutes to approximately 12 minutes). In addition, certain operator actions specified by the abnormai procedure were reclassified from being supplemental actions to immediate actions, such that the operators would be required to have them memorized. This would then allow operators to take those actions without having to refer to the procedure to do s _ - _ __ ._- _______ _ _ - _ -
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The inspectors felt that incorporation of the two additionalinterim compensatory measures would provide operators additional time and guidance to mitigate the event. However, the probabilistic safety analysis report described a condition that was allowed to exist for over a year whereby operators would not have had sufficient time to respond to a specified accident sequence were it to occur. As such, this matter is considered a violation (50 346/97009-04(DRP)) of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Actions", in that measures were not established to assure that a condition adverse to quality was both properly identified and corrected. In this particular case the interim compensatory measures were not adequately established and implemented in a timely manne E8.5 (Closed). Inspection _Eollo wup. Item _(50.146196005-021DRPJ): Review of selected makeup pump design requirements. Existing procedural guidance for preventing makeup pump cavitation was inconsistent, and sometimes in error, in response, makeup pump operating curves (that specified the amount of makeup tank cover gas pressure required to ensure adequate net positive suction head to the pumps while the makeup tank was in service) were relocated to a single curve sheet. These curves were properly labeled and provided a simple calculation for obtaining total makeup pump flow values. Additionally, these curves were extended from a previous limiting value of 150 gpm up to the runout capacity of the makeup pumps (350 gpm). References from the makeup and purification procedure were changed to direct net positive suction head restrictions to this curve sheet. The hydrogen and degas procedure was changed to specify the correct minimum makeup tank pressure
to prevent cavitation. Overall, af ter implementation of the above changes to plant documentation, clear and consistent procedural guidance was available to prevent
! cavitation of the makeup pumps during normal and accident conditions.
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Additionally, an equipment concern was originally identified which involved the capability of the makeup tank to withstand low pressure injection pump discharge pressure during low pressure injection piggyFack operation while the makeup pump suction three-way valves were repositioning, The makeup tank relief valve was analyzed to be able to relieve the flow frc.n the low pressure injection pump before the design pressures of the makeup tank would have been exceeded. Additional measures were taken to ensure that procedure DB-OP-02000. "RPS, SFAS, SFRCS Trip, or SG Tube Rupture", consistently provided guidance to the operators to check that the makeup pump three-way suction valves completed their stroke when suction was transferred to the Borated Water Storage Tan E (OpenLunresolvedJtem_(50-346197D03A4(DRPJ) Service water strainer biowdown valves failed to automatically close on several occasions. This relates to a service water strainer blowdown valve control circuit that permitted the blowdown valve to remain partially open. The valve could remain partially open following a service water pump high discharge pressure condition. This high pressure condition would cause the blowdown valve to begin to open to provide for minimum pump cooling flow. When the blowdown valve started to open, the service water discharge pressure would decrease until the high pressure relay reset, which would stop the valve from opening. If the valve had not stroked past a 20 percent open positio the control circuit would not automatically close the valve and the valve wou!d
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remain open. No indication of blowdown valve position was available to control room operators and the condition would only be noticed by direct observation of the valve stem position. The condition of the blowdown valve being found in a less than 20 percent open position was actually observed by the inspector in the field. This was a problem in that safety-related service water fiow could be unknowingly diverted through the blowdown valve during a design basis even Subsequently, all three service water strainer blowdown valve control circuits were modified to prevent the valve from remaining partially open. A sealin contact was installed in the opening portion of the circuit to ensure that the valve would open past 20 percent, which would allow the blowdown valve to subsequently clos Performance engineering personnel conducted a review of other safety-related, motor-operated valve control circuit designs to determine if any other circuits had a similar design. Based on this review, the licensee identified that several safety-related valves would not close if the open cycle was interrupted before reaching 20 percent open. However, after further investigation, the licensee determined that no automatic opening signals existed for these valves. Also, valves that had stroked partially open due to a loss of power to the motor operator had valve position indication and control available from the control room once power was restored to the associated breaker. Additionally, operators had been trained that if a valve in an intermediate position would not shut, to try and first open then shut the valve. This practice would cause the valve to open past the 20 percent open position which would enable the valve to subsequently be closed. The service water strainer blowdown valve, because it could receive an intermittent open signal via a service water pump high discharge pressure condition, and did not have remote valve position indication in the control room, was a special cas In addition, plant engineering personnel were completing remedial corrective actions and an extent of condition review pertaining to the separate issue of an age-related degradation of a control circuit auxiliary relay to one of the service water strainer blowdown valves. This review was due to be complete at the end of October. The subject issue involved a latch in auxiliary relay that intermittently failed to latch in because of a " relay-race" phenomenon, which caused the blowdown valve to fail to automatically close after having been automatically stroked open. This condition diverted service water from downstream essentialloads. The extent of condition review has thus far resulted in the identification of about 25 additional safety-related control circuits that may be susceptible to an identical" relay race" aging phenomenon. The inspectors will complete their review of this part of the open item upon completion of the licensee's revie PL_ Plant. Support R1 Radiological Protection and Chemistry (RP&C) Controls The inspectors conducted frequent walkdowns of the radiological restricted area during the inspection period. Radiological postings were verified to be appropriat . . . .
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Actual radiological conditions were independently verified to be consistent with radiological survey maps. Several personnel performing operational and maintenance activities in the radiological restricted area (RRA) conducted those activities in accordance with radiation protection requirement R8 Miscellaneous RP&C issues R l it'le.t*rit t FR sin.'%B191.nna.nn nnrh t'nntmininent BadiationManitats_laoperable Due rn Miecing Caskets. Due to licensee identification that the top outside gasket for the particulate filter holder on one of the two station vent normal radiation monitors was missing, additionalinspection of other plant radiation mon 8 s was initiated. Subsequently, on February 25,1997, with the plant at full power, the licensee iden~tified that both containment normal range radioactivity monitors were missing gaskets on their associated particulate filter and iodine cartridge holder Davis.Besse Technical Specifications require that three separate systems be operable to identify primary system leakage within containment, with the subject radiation monitors comprising one of the three system The licensee subsequently determined that with the particular gaskets missing, a small amount of sample flow would bypass the filter and thereby result in a slight downward shift in the radioactivity monitor response time. Although this shift could not be quantified without extensive testing,it appeared the effect on response time would be minor due to the close tolerances between the filter holder and filte The licensee's corrective actions included an inspection of all applicable radiation monitors to identity any additional missing gaskets. in addition, procedures in place to address the replacement of radioactivity monitor filters of this type were revised to include appropriate steps to verify all necessary gaskets were installed upon completion of wor P8 Miscellaneous Emergency Plan issues P (Closadi inspection _Eollawup_ Item _150346/97006-06(DRPJ1: Emergency plan evacuation routes potentially affected by postulated flooding conditions. When the licensee became aware that the Army Corps of Engineers had projected potentially significant flooding conditions during the summer and fall of 1997, additional reviews of the emergency plan evacuation routes were conducted. The reviews included evaluation of local topographical maps to identify additional roadways that could possibly be submerged during the postulated storm / rainfall conditions. That evaluation was subsequently completed with no significant adverse effects to the current emergency evacuation plan being identifie F8 Miscellaneous Fire Protection issues F (Closedlunresolved _ltem_(50-3461960 R06(DRP)): Fire brigade captain qualifications. The fire brigade captain function was routinely assigned to the outside assistant shift supervisor. The control room staffing board indicated that thu outside
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0 9 assistant shift supervisor (who was not qualified as a fire brigade captain) was the fire brigade captai The inspectors subsequently determined that the placard placed on the control room staffing board that designhted the fire brigade assignments was not officially considered the sole designator and that the control room assistant shift supervisor (who was fire brigade q'talified) was officially designated by operation's shift management to respond to a fire as the fire brigade captai The control room assistant shift supervisor had pre staged his fire brigade equipment and gear, and provisions bad been made for the outside assistant shift supervisor to relieve the control room assistant shift supervisor in the event of a fire. Once that .
turnover was complete, the control room assistant shift supervisor, a qualified fire brigade leader, was then free to fulfill the fire brigade captain function The inspectors were concerned that having the control room shift supervisor designated as the fire brigade captain imposed unnecessary delays in manning the fire brigade in the event of a station fire. Additionally, the outside assistant shift supervisor would receive a brief turnover from the control room assistant shift supervisor and therefore might not obtain the necessary details of plant condition However, no plant procedures or NRC regulations identified a required fire brigade response time. The assistant shift supervisor who was not fire brigade captain I qualified, subsequently completed his qualifications for that position. This matter is close V_ Mnnagement_Mentings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on August 18,1997. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie i
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PARTIAL UST OF PERSONS CONTACTED =
Ucansee J. H. Lash, Plant Manager J. L. Michaelis, Manager, Maintenance D. L. Eshelman, Manager, Operations D. M. Imlay, Superintendent Operations INSPECTION PROCEDURES USED
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IP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities i
I 92700: Onsite Fo:ow up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Followup - Plant Operations IP 92902: Followup - Maintenance IP 92903: Followup Engineering IP 92904: Followup - Plant Support l
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. O ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50 346/97009-01(DRP) VIO Shift supervisor authority to perform procedure steps out of orde /97009 02(DRP) NCV Switchyard circuit inoperable 50-346/97009-03(DRP) URI No CCW Integrated leak rate testing had been done and no system leakage acceptance criteria had been
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established 50 346/97009-04(DRP) - VIO interim compensatory measures not established cinnad 50-346/97308-01(DRP) URI Control of temporary changes to procedures 50-346/96002-01(DRPI URI Safety Features Actuation System channel operability l
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during certain surveillance testing activities 50-346/96002-10(DRP) VIO One High Pressure injection line not vented in accordance with TS 452b 50 346/96006-02(DRP) IFl Reader / worker practices j 50-346/96014-04(DRP) VIO Violation of 10 CFR 70.24 relating to failure to install radiation monitoring in the Davis-Besse new fuel storage area capable of alarming in response to a postulated accidental criticality 50-346/96010-04(DRP) URI Placement of portable equipment within the control room without adequate engineering evaluation 50-346/97008 05(DRP) URI Postulated Circulating Water system pipe break analysis 50 346/96005-07(DRP) IFl Review of selected makeup pump design requirements 50-346/97006-06(DRP) IFI- Emergency plan evacuation routes potentially affected by postulated flooding conditions 50 346/96014-06(DRP) URI Fire brigade captain qualifications 50-346/96-008-00 LER Switchyard Circuit inoperable Due to Switchyard Breaker Alignment 50-346/97-004-00 LER Reactor Coolant Pump Motor Oil Piping Not Protected from Leakage As Required Per 10 CFR Part 50, Appendix R 50-346/97-006 00 LER Both Containment Radiation Monitors Inoperable Due to Missing Gaskets 50-346/97009-02(DRP) NCV Switchyard Circuit inoperable pine. . ... A 50-346/97003-04(DRP) URI Service water strainer blowdown valves failed to automatically close on several occasions
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LIST OF ACRONYMS AND INITIALISMS USED CFR Code of Federal Regulations '
ESF- Engineered Safety Feature ,
I&C Instrumentation and Controls IFI' Inspection Fntlowup ltem IR' Inspection her, ort MWO Maintenance Work Order -
NCV Non-Cited Violation NRC - Nuclear Regulatory Commission PCAOR Potential Condition Adverse to Ouality Report PDR Public Document Room RRA - Radiological Restricted Area TS Technical Specification
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