IR 05000334/1988001
| ML20148A558 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/09/1988 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20148A555 | List: |
| References | |
| 50-334-88-01, 50-334-88-1, 50-412-88-01, 50-412-88-1, IEB-88-002, IEB-88-2, IEIN-88-005, IEIN-88-5, NUDOCS 8803210008 | |
| Download: ML20148A558 (30) | |
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V. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /88-01 License: DPR-66 50-412/88-01 NPF-73 Licensee: Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Units 1 and 2 Location: Shippingport. Pennsylvania Dates: January 1,1988 - February 15, 1988 Inspectors: J. E. Beall, Senior Resident Inspector . P ndal , Resident Inspector Apprc,ved By: o
.Lowell E. Tri h, Chief ' Date Reactor Projects Section No. 3A IrLspection Summary: Combined Inspection Report Nos. 50-334/88-01 and 50-412/88-01 - January 1, 1988 through February 15, 1988
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Areas Inspected: Routine inspections by the resident inspectors (376 hours0.00435 days <br />0.104 hours <br />6.216931e-4 weeks <br />1.43068e-4 months <br />)
of licensee actions on previous inspection findings, plant operctions, main-tenance activities, surveillance testing, diesel generator air start motor lubrication followup, fitness for duty program, Unit 1 refueling outage activ-ities, activities associated with the Unit 2 Alert declaration on January 23 due to annunciator loss, Unit 2 line freezing due to cold weather, review of calibration program, review of periodic and special reports and review of licensee event report Results: No violations or unresolved items were identifie Six NRC open items were closed during this inspection, while three were updated but remain ope An NRC followup item was opened to track licensee resolution of NRC Bulletin No. 88-02, Rapidly Propagating Fatigue Cracks in Steam Generator Tubes (Detail 9.7). Licensee weaknesses identified during the inspection included housekeeping conditions (Detail 4.5) and a recently submitted licensee event report (Detail 15). The licensee's response to the Alert on January 28 was noted as a strength (Detail 10).
8803210008 880310 PDR ADOCK 05000334 o DCD
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A TABLE OF CONTENTS Page 1. Persons Contacted. . . . . . . . . . . . . . . . . . . . . . . . 1 2. Summary of Facility Activities . ................ 1 3. Followup on Outstanding Items. . . . . . . . . . . . . . . . . . 1 4. Plant Operations . . . . . . . . . . . . . . . .. . ... 5 4.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . 5 4.2 Operations. . . . . . . . . . . . . . . . . . ....... 5 4.3 Plant Security / Physical Protection ... ...... 8 4.4 Radiological Controls . ................. 9 4.5 Plant Housekeeping and Fire Protection ......... 9 5. Maintenance Activities . . ................. 10 6. Surveillance Testing . . . ... ......... ... 11 7. Diesel Generator Air Start Motor Lubrication Followu; . ..... 12 8. Fitness for Duty Program . ... . .......... . 13 9. Unit 1 Refueling Activitie ...... ........... 14
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9.1 In-Core Instrumentation Thimble Tube Wea ..... ... 14 9.2 Tool and Material Controls . . .......... ... 15 9.3 Design Change Package Review . .. ... ......... 15 9.4 Feedwater System Piping Cracks . . . . . . . . . . . . . . . 16 9.5 Cycle 6 Fuel Failures. .. ..... ........ 17 9.6 Thermal Shield Bolt Replacemen .... ......... 18 9.7 Steam Generator U-Tube Inspectio ........... 19 10. Unit 2 Alert Due to Annunciator Loss . ............. 20 10.1 Annunciator Cabinet Fir ..... .. .. ... . 20 10.2 Emergency Plan Implementation . . ...... ...... 20 10.3 Event Followu .. . . .......... ....... 21 10.4 Revision of Emergency Preparedness Plan . . ...... 22 10.5 Summary . . .. . ......... .... .. 23 11. Unit 2 Line Freezing Due to Cold Weather . ........... 23 11.1 Refueling Water Storage Tank (RWST) Lesal Instruments . . . 23 11.2 Quench Spray Recirculation Line . ............. 24 i
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Table of Contents (Continued)
Page 1 Calibration Progra ..... ................ 24 13. Allegation on Document Control . . . . . . . . . . . . . . . . . 25 1 Review of Periodic and Special Reports . ............ 25 1 Inoffice Review of Licensee Event Reports (LERs) . . . . . . . . 26 1 Exit Interview . ....................... 27
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DETAILS 1. Persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspec-tion activitie . Summary of Facility Activities At the beginning of the inspection period, Unit I was defueled in the Cycle 6 refueling outage and Unit 2 was operating at approximately 100%
power. During the period, Unit I reloaded fuel and had progressed to Mode 5 at the conclusion of the period. Unit 2 experienced a reactor trip on January 27, following the apparently spurious overcurrent trip of a 4 kV bus (see section 4.2.1) . The licensee elected to cool down to conduct some maintenance activities, including a license-required first cycle snubber inspection. On January 28, a loss of annunciators occurred in the Unit 2 control room which resulted in the declaration of an Alert at 7:20 p.m. (see sections 4.2.2 and 10) . The licensee was able to restore the annunciators and the Alert was terminated at 10:45 Unit 2 was started up on Februuy 12 and was placed on the grid on February 13. Unit 2 was at 100?; power at the close of the inspection perio . Followup on Outstanding Items The NRC Outstanding Items (01) List was reviewed with cognizant licensee personne Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspection to determine whether licensee actions specified in the OIs had been satisfactorily complete The overall status of previously identified inspection findings were reviewed, and planned / completed licensee actions were discussed for those items reported below:
3.1 (Closed) Unresolved Item (50-334/84-25-01): Resolve possible mis-applicatian of the P-6 rela A large number of failures of the neutron source range monitor (SRM) detectors prompted the investiga-tion into the application of the P-6 unit, which is designed to remove the high voltage power supply to the SRMs during plant start-
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ups (when above 10';). The relay vendor (Westinghouse) reported that I the problems at BV-1 were not considered to be the result of a mis-
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application of the rela The licensee's short term corrective action was to remove electrical power to the SRMs when the reactor power is above 10's. This was achieved by d'recting plant operators l to physically remove the electrical fuse The fuses are replaced l
when the reactor power level is decreased to 10'; or les NRC
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Inspection Report No. 50-334/86-21 updated this item and left it open pending implementation of a long term corrective action plan. Fol-lowing several investigations and evaluations, the licensee deter-mined that the most conservative approach to resolve this problem was to continue to implement current corrective actions (fuse removal).
The basis for this decision was that, absent a major system modifi-cation, separate fixes to the system may be prone to further inad-vertent SRM detector failures, leading to system unavailabilit Further, the plant operators have been trained and procedures revised to reflect current practices of fuse removal and installation. Addi-tionally, during the Sixth Refueling Outage, the licensee installed permanent fuse holders directly above the SRMs in the control room so that the fuses will be maintained in a controlled manner and be readily available when needed. The inspector determined that plant operators have been adequately instructed regarding the required actions and that the applicable procedures have been revised to reflect fuse removal / installation requirement No additional con-cerns were identifie This item is close .2 (Closed) Unresolved Item (50-334/84-28-02): Preventive Maintenance (PM) and shelf-life program for in-storage equipment / material was not effectively implemented. The licensee cu rently implements an inter-nal PM program for in-storage components which utilizes both standard industry practices and vendor recommendation A similar program exists for component shelf life. A new, computerized system iden-tifies those components requiring PM or having shelf life require-ments. The inspector reviewed the new system and determined that it appears to be more flexible than the old computer system. The system is essentially completed and implemented. Included in the remaining work on the system is a physical verification of component require-ments (computerized listed database vs. actual requirements). The licensee expects this verification to be complete before the end of 198 This issue was also reviewed in NRC Inspection Report N /86-08 (Pu"chasing and Storage). No concerns were identified in the repor The inspector will review the effectiveness and the complete implementation of this system during a subsequent inspectio This item is close .3 (0 pen) Unresolved Item (50-334/85-20-03): Upgrade stores administra-tive controls to ensure critical parts are automatically reordered prior to depletion. During the week of September 23, 1985, qualified spare parts were not available in the warehouse on two occasions due to having reorder levels of zero. The licensee has reduced the back-log of known ittms requiring reordering utilizing the present rnanual system in which parts are reordered when an individual physically notices that part quantities are lo The licensee is currently planning to add a feature to the existing computerized system to automatically generate listings when parts need to be ordered. This is expected to be completed by July, 1988. Pending implementation of this automated feature, this item remains ope _. _ . __
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3.4 (Closed) Unresolved Item (50-334/85-20-04): Update Technical Spec-ification (TS) Table 2.1-1, Reactor Trip System Instrumentation Trip Setpoints. The NRC issued Amendment No. 118 to the Unit 1 TSs on November 13, 198 The inspector reviewed the TS amendments and verified that controlled TSs have been updated to reflect the recent changes. Plant procedures affected by this TS amendment have not yet been revised, however, a procedure change request form has been filed to the appropriate organizatio The licensee stated that the pro-cedures will be revised before the next scheduled performance of the associated tests (September, 1988). The inspector reviewed the latest completed calibration procedures, which indicate that the new TS requirements have been previously implemented and satisfied, al-though the upper limits on the time constant for the associated lag compensator terms had not yet been incorporated into the procedure Implementation of the requested procedure changes will be reviewed during a subsequent routine inspection. This item is close .5 (Closed) Unresolved Item (50-334/86-15-01): This item was updated in NRC Inspection Report No. 50-334/87-02, which identified an air-borne contamination concern regarding current refueling cavity de-contamination practice The licensee subsequently implemented a different method of decontaminating the reactor cavit The new method uses a strippable coating in the cavity, a method which both reduces the potential for airborne contamination and eliminates the use of extensive de-mineralized water (which previously led to a boron dilution event on July 14, 1986). The hydrolazing technique is still used, however only for the transfer canal area. Both de-contamination evolutions were successfully performed during the Sixth Refueling Outage. Similar problems to those experienced previously were not experience This item is close .6 (Closed) Unresolved Item (50-334/86-21-01): The licensee was to review vendor requirements with respect to emergency diesel generator l (EDG) electric space heaters. In response to this item, the licensee developed Design Change Package (DCP) No. 799, EDG Strip Heaters, to be implemented during the Sixth Refueling Outag The inspector reviewed DCP 799 and confirmed that the modification implemented the EDG vendor (General Motors, Electro-Motive Division) recommendations, including the installation of two 750 watt strip heaters just below each EDG windin The purpose of the DCP was to keep the windings dry while the EDGs are not in service, improving reliability and l service life of the generator winding The inspector verified that l the modification was completed during the refueling outage for both EDGs and was conditionally accepted by the licensee. Open items that remained were: (1) drawing revision, (2) operator DCP training and (3) maintenance training EDG lesson plan revisions. The inspector verified that open item Nos. I and 2 have been completed. The third item and final system acceptance will be verified during a subsequent routine inspectio This item is closed.
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3.7 (Closed) Unresolved Item (50-334/86-29-01): Determine the cause of failure of charging pump (CH-P-1B). The licensee reviewed the re-sults of a vendor metallurgical examination of the charging pump shaft. The inspector reviewed the licensee's followup report, which documented several potential causes and fixes for the shaft failur Most of the potential causes have been eliminated by subsequent shaft design changes, charging system modifications and improved mainten-ance techniques. One additional potential cause identified by the licensee is air entrainment in the charging pump suction and dis-charge line Design Change Package (DCP) No. 830, Charging Pump Suction and Discharge Line Vents, is currently scheduled to install permanent tubing and valving to allow charging pump venting on a periodic basis while the plant is operatin Implementation of DCP 830 is a non-outage modification and is expected to be implemented by December, 198 The effectiveness of the licensee's corrective actions will be reviewed during subsequent routine inspections. This item is close .8 (0 pen) Violation (50-334/87-06-03): Failure to properly prepare /
review equipment clearances. The licensee responded to the violation as required by letter dated July 26, 1987. The licensee's action taken to p. event recurrence included holding discussions with plant operators regarding proper configuration control requirements, good operating practices and the use of proper valve status boards to identify and correct system alignments for placement of clearance On February 6, 1988, the inspector walked down several equipment clearance permits. The components in the plant were physically in
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the correct position in accordance with the associated permits, how-ever, a review of the control room status prints identified discrep-ancies regarding administrative control of the control roem print Specifically, although the affected components were shown in the proper (cleared) position, the status prints did not note the equip-ment clearance permit that the inspector was reviewing. That is, a different clearance was referenced as being the clearance which placed the component in the cleared positio The inspector dis-cussed these discrepancies with the licensee and noted the potential for the status prints not to reflect actual plant configuratio For example, if the permit that was logged on the prints was removed, the affected components could possibly be shown on the prints to be in their normal system alignment versus the cleared alignment due to another permi The licensee acknowledged the inspector's comments and immediately initiated a physical check of all outstanding equip-ment clearance permits and the status prints; no additional discrep-ancies were identified during the review. Additionally, the licensee provided further instructions to plant operators regarding proper control of the status print The repetitive nature of this item indicates that additional action may be required to ensure that the status prints are properly upgraded and reflect current plant con-figuration This item will remain open pending verification that this was an isolated incident.
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3.9. (0 pen) Violation (50-334/57-10-01): This item cited two violations (categorized in the aggregate as one Severity Level. IV Violation)
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concerning chlorine detection system (CDS) deficiencies. The licon-see responded to the violation as reauired by letter dated August 31, 198 Licensee corrective actions included (1) the in-stallation and satisfactory testing of a new CDS, which utilizes probes located directly in the control room ventilation flowpath (similar to the Unit 2 CDS), (2) review of acceptance testing of all installed design changes that affected systems similar to the CDS (i.e., gas detection and monitoring and radiation monitoring systems), *
which did not identify any additional similar concerns and (3) imple-mentation of upgraded reauirements (performed subsequent to 1980) for design change acceptance testing to specify that full operational testing under normal operating conditions of design changes be per-formed whenever feasible (unless such testing would result in opera- i tional/ safety hazards). The inspector reviewed the licensee's cor- :
rective actions and no significant deficiencies were identifie Problems were experienced with the periodic response time testing of the CDS in-line probes. Many performances of the monthly calibration procedure, MSP 44.11, Control Room Chlorine Detection Probe Calibra-tion, found response times inadequate. Subsequent discussions be-tween the licensee and the CDS vendor resulted in changing the time ,
interval between MSP performance The licentee is currently plan-
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ning to perform the MSP once every seven days to ensure the instru-ments remain within calibration requirement Unit 2 uses the same vendor and components in their CDS, however, that system has not been
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due to being unable to positively identify an adequate test method of the system. Although the system components are the same for both units, piping arrangements are differen The vendor and licensee are currently pursuing the testing concerns for the Unit 2 CO For the interim, the control room ventilation system has been placed in a
recirculation mode of operation per TS 3.3.3.7 (Chlorine Detection '
i Systems) requirements. This item remains open pending resolution and implementation of appropriate testing requirements for both Unit 1 and Unit 2 Chlorine Detection System . Plant Operations I 4.1 General l Inspection tours of the following accessible plant areas were con-ducted during both day and night shif ts with respect to Technical 1
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Specification (TS) compliance, housekeeping and cleanliness, fire
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protection, radiation control, physical security / plant protection and operational / maintenance administrative controls.
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-- Control Room -- Safeguard Areas
-- Auxiliary Building -- Service Building
-- Switchgear Area -- Diesel Generator Buildings
-- Access Control Points -- Containment
-- Protected Area Fence Line -- Yard Area
-- Turbine Building -- Intake Structure 4.2 Operations During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changed to procedures, facility configuration and plant conditions. During plant tours, logs and records were reviewed to determine if entries were properly made, and that equipment status / deficiencies were identified and communi- '
cated. These records included operating logs, turnover sheets, tag-out and jumper logs, process computer printouts, unit off-normal and draft incident reports. The inspector verified adherence to approved procedures for ongoing activities - observe Shift turnovers were witnessed and staf.fing requirements confirmed. In general, inspector '
comments or questions resulting from these reviews were resolved by licensee personne Inspections conducted during backshifts and weekends verified that plant operators were alert and displayed no signs of fatigue or inattention to dut Backshift and weekend inspections were performed on January 17, 28 and February 6, 7 and 12, 198 . On January 27,1988, Unit 2 experienced a reactor trip from 100*J power due to the loss of power to the "A" RCP, Within 'i milliseconds af ter securing a service water pump powered from the "A" 4 KV bus, an overcurrent alarm was received and the bus tripped on overcurrent. The "A" RCP is powered .
from the "A" 4 KV bus and loss of the RCP resulted in a scram on low flo The service water pump breaker is located in the "AE" por-tion of the bus which has the "A" 4KV bus as a normal i source and the 2-1 emergency diesel generator (EDG) as a backu The "A" 4KV bus was de-energized by the trip because a trip on overcurrent prevents the bus from at-
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tempting to transfer automatically to its alternate source from offsite powe The 2-1 EDG auto-started due to the
! sustained loss of voltage on the "AE" bus and restored
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power to the safety-related equipment, including the
service water pump which was secured at the onset of the even I I
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, I The licensee elected to cool down to Mode 5-(Cold Shutdown)
and begin early a planned maintenance outage. The inspec-tor reviewed the licensec's' investigation of the bus tri The service water pump was ' started. and stopped several times but the bus trip did not reoccur. All of the relays were removed end replace Bench testing of the ' devices identified no deficiencies which could have produced the trip and the relays were sent to the original vendors for further testin The inspector reviewed +he licensee's troubleshooting
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activities and witnessed some of the tests; no deficiencies were identified.
- 4. On January 28, 1988, Unit 2 experienced a loss of annuncia-tion while in Cold Shutdown (Mode 5). The unit was cooling
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down following the earlier plant trip (See Section 4.2.1)
when: erratic visual window display and horn operation occu'rred. A small fire was detected in a remote annuncia-tor cabinet and immediately extinguished by two operators who had been dispatched to investigate. Due to a sustained i loss of annunciators, the licensee declared an Alert in i
accordance with the Emergency Plan. All notifications were made as required by the Alert declaratio The damaged solid state cards were removed and annunciation was re stored to all but a few known alarm windows. The Alert was terminated at 10:45 p.m. following the restoration of ;
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annunciation capabilit Radiation protection specialist inspectors were onsite at the time of the event; the
resident inspector was dispatched from his home, and NRC coverage was maintained throughout the Aler For additional details ~see section 10 and also NRC Inspec-i tion Report No. 50-412/88-0 . Automatic Diesel Generator Start !
, On February 1, while in Mode 5 (Cold Shutdown), the Unit 2
"AE" emergency bus was inadvertently de-energized while technicians were troubleshooting the bus overcurrent rela "
The troubleshooting activities were being performed as licensee followup action to the reactor trip from full power on January 27,1988 (See Detail 4.2.1). The loss of the "AE" bus resulted in an automatic start of the No. 2-1 emergency diesel generator (EDG). The control room emerg-ency bottled air pressurization and supplementary leak '
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collection and release (SLCR) systems also _ automatically actuated due to the loss of the "AE" bus after their asso-ciated radiation monitors lost control powe Power was
, subsequently restored to the "AE" bus and the EDG was
, manually shutdown after about 17 minute The licensee made the required notifications in accordance with 10 CFR 50.72 reporting requirement Prior to the event, the "A" train of the SLCR system was operating with the "B" train. isolated (normal system align-ment). When the "AE" bus was lost, the "A" train dampers upstream of the SLCR fans automatically closed as per sys-tem design. Since the "B" train dampers were also isolated
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per normal system alignment, SLCR ' system exhaust flow was isolated and the control room leak collection exhaust low flow alarm annunciate To reinitiate SLCR system flow in this condition, plant operators were required to manually open the associated B train dampers and SLCR system flow was re-established. The licensee subsequently requested that an engineering evaluation be performed to investigate either (1) changing the failure mode of the dampers .or (2)
modifying the .ircuitry to incorporate an automatic opening feature for the dampers in the isolated train following a loss.of power and consequent closure of the operating train damper For the interim, plant operators have been instructed on the required manual actions to restore system
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operation. Plant procedures also provide. the necessary instructions to the operator The inspector will review the effectiveness of these interim corrective actions and permanent resolution of this item during a subsequent inspectio No additional concerns were identifie .3 Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:
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Protected Area and Vital Area barriers were well maintained and not compromised;
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Isolation zones were clear;
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Personnel and vehicles entering and packages being delivered to the Protected Area were properly searched and access control was in accordance with approved licensee procedures;
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Persons granted access to the site were badged to indicate whether they have unescorted access or escorted authorization;
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Security access controls to . Vital Areas were being maintained and that persons in Vital Areas were properly authorize Security posts were adequately staffed and equipped, _ security personnel were alert. and knowledgeable regarding position requirements, and that written procedures were available; an Adequate illumination was maintaine No concerns were identifie .4 Radiological Controls Posting and control of radiation and high radiation areas were in-specte Radiation Work Permit compliance and use of personnel mon-itoring devices were checked. Conditions of step-off pads, disposal of protective clothing, cleanliness of work areas, radiation control job coverage, area monitor operability and calibration (portable and permanent) and personnel frisking were observed on a sampling basi Significant concerns were not identified during this inspection. For more detail on both routine and outage related activities with respect to radiological control, see NRC Inspection Report No /80-03 and 50-412/88-0 .5 Plant Housekeeping and Fire Protection
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Plant housekeeping conditions including general cleanliness condi-tions and control and storage of flammable material and other poten-tial safety hazards were observed in various areas during plant '
tours. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed. The inspector conducted detailed walkdowns of the access-ible areas of both Unit 1 and Unit The inspector expressed the concern t. .a t items such as improperly secured gas bottles, unsecured gas bottles and wheeled devices were still being found near sa fety-related equipmen In addition, a temporary laydown area of boards, ladders and scaffolding material was found by the inspector to be stacked around and against a Unit 2 containment isolation valve, the containment purge exhaust valve (2M00-23A). At the time, Unit 2 was in Mode 3 preparing for reactor startu After identification by the inspector, the individual deficiencies were corrected and, in the case of the temporary laydown area, a'l material was removed before startu .. .
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The inspector met with the QA Manager and members of his staff to assess the role of the QA Department in the area of material contro The inspector determined that QA inspections and audits were being performed in this area and the QA Manager indicated that the resources being allocated in this area would be reassesse The inspector reviewed the startup checklists and noted that organizational sign-offs were required (prior to Mode 3) that attested that hot process lines had been walked down for hazards. No similar signoffs were found addressing material with the potential for interfering with safety equipment required to be operabl The inspector expressed his concerns to senior plant management dur-ing the course of the inspection and noted at the exit meeting that this area exhibited weakness during the perio The inspector will continue to monitor the licensee's performance in this area, especially during the Unit 1 startu . Maintenance The inspector reviewed selected maintenance activities to assure that:
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the activity did not violate Technical Specification Limiting Condi-tions for Operation and that redundant components were operable;
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required approvals and releases had been obtained prior to commencing work;
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procedures used for the task were adequate and work was within the skills of the trade;
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activities were accomplished by qualified personnel;
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where necessary, radiological and fire preventive controls were ade-quate and implemented;
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QC hold points were established, where required, and observed;
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equipment was propsrly tested and returned to servic Maintenance activities reviewed included:
MWR 885251 Replace Oil Pump / Motor on Main Transformer MWR 872904 Repair 2SSR-RV-133 MWR 880099 Replace / Repair Test POT for RPI Test Panel
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MWR 880151 Repair /Recrimp Broken Wire on Inverter N , 3 Bypass Transformers MWR 88'c 207 Calibrate SI Branch Flow Transmitter for OST 1.11.14 MWR 882257 Replace Accelerometer on RS-P-2B MWR 882263 Repair Low Side Isolation Valve For SG IC with Range Level Transmitter No problems were identifie . Surveillance Testing The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used, Technical Specifi-cations were satisfied, testing was performed by qualified personnel and test results satisfied. acceptance criteria or were prcperly dispositione The following serveillance testing activities were reviewed:
Unit 1:
OST 1.11.14 Full Flow Safety Injection Pump Test OST 1.11.18 Low Head Safety Injection Pump Boric Acid Flow Path Veri fication OST 1.1 Recirculation Pump Dry Test OST 1.1 Recirculation Pumps Automatic Start and Flow Test OST 1.1 Fuel Building Ventilation System Verification OST 1.2 Spent Fuel Pool Level Verification OST 1.2 Motor Driven Auxiliary Feed Pump Test
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OST 1.30.12 Recirculation Spray Heat Exchanger Flow Test l
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OST 1.4 Shutdown Margin Calculation MSD 1.15 Reactor Trip and ESF Logic Time Response l
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OST 2.1 Containment Depressurization System Position Verification Test OST 2.1 Supplementary Leak Collection and Release Exhaust Fans and Remote Damper Component Test OST 2.2 Auxiliary Feedwater System Valve Exercise and Flow Verification OST 2.3 Service Water Pump Test No concerns were identifie . Diesel Generator Air Start Motor Lubrication Followup The Unit 1 emergency diesel generator vendor, General Motors, Electro-Motive Division (EMD), .provided an advisory to owners dated July 13, 1987, which recommended increasing the rate of lubrication to specific manufac-turer air start motors by a factor of between 20 and 40. The air start motors affected are those manufactured by Ingersoll-Rand. No justifica-tion was provided by EMD for this radical change to the recommended main-tenance program. The inspector interviewed several licensee personnel to determine the status of the affected Ingersoll-Rand equipment on site, and to verify the effectiveness of the licensee / vendor interface. The licen-see subsequently determined that the advisory had not been received. The inspector then orovided the licensee with a copy of the advisory (see Attachment to this report). The inspector noted that the Unit 2 diesel generators are not affected by this issue since their air start motors are from a different manufacture Additional inspection activities related to this item included a review of maintenance history data associated with the air start motors to deter-mine whether previous failures / problems existed that were due to inade-quate lubrication. The inspector noted that when the motors are removed for maintenance (preventive or corrective), they are sent to an off-site contractor for refurbishing. Several of the reports (about six) over the past three years for the Unit 1 air start motors include suggestions from the vendor that the air start motor installer inspect the lubricator and air supplies on the equipmen Two reports documented the reason for failure to be improper lubrication. The preventive maintenance program inspects / replaces these motors on an 18 month interva The inspector questioned the basis for an 18 month interval for air start motor preven-tive maintenance, considering the relatively large number of failures /
problems that have occurred over the last few year The licensee stated that a modification, implemented during this refueling outage, was intended
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to increase reliability of the air start motor syste Specifically, Design Change Package No. 576, Diesel Generator Air Start System Modifica-
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tions,' added pulsation dampers and air dryer units to the diesel generator start. system: (1) to absorb any rapid pulses out of the air compressor and (2) to remove moisture from the air used in the air starting system. In response to the inspector's concerns, the licensee stated that the his-torical and current operating / reliability data for the diesel generator would be reviewed with respect to the air start motors and recommendations provided for the preventive maintenance program as necessary. An inspec-tion of the air start system associated with one of the diesel generators will be performed by about June, 1988 to evaulate the effectiveness of recent system modifications. The results of this licensee investigation
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will be reviewed during subsequent licensee inspections.
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Regarding the potential vendor / licensee interface problem, the licensee
- stated that they would contact EMD and determine the distribution status i
of Duquesne Light Company and verify similar previous distribution problems have not occurred with this vendor. Additionally, the licensee plans to select a sample of vendors, particularly those from which no recent publications have been received, and confirm that the vendor /
licensee interface is adequate. The inspector will review the results of this action during a future inspectio . Fitness for Duty Program
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On January 8,1988, the resident inspector received an anonymous allega-i tion of substance abuse involving two contractor technicians. NRC manage-ment subsequently notified licensee management personnel of the allega-tio The licensee then asked the two technicians to submit to drug test-
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ing later that day in accordance with the licensee's Fitness For Duty Program. One individual declined to be tested, was escorted offsite and
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the individual's site access was terminated. The second individual agreed to submit to testing, however, the results were positive for cocain That individual was escorted offsite on January 13, when the results became available, and that individual's access was also terminate The licensee's response to this issue was in accordance with the Fitness for Duty Progra The inspector also reviewed the records and data associated with the licensee's Fitness for Duty Program with respect to the NRC Fitness for Duty Policy Statement, effective August 4, 1986, in the Federal Register
!. (51 FR 27921). The inspector determined that the licensee had established
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appropriate administrative requirements regarding responsibility and I
authority for determining when a chemical test for drugs or alcohol will be performed "for cause." Specific threshold limits for positive limits had been established. The inspector confirmed that the licensee's Fitness for Duty Program is publicized including distribution to all new employees. The licensee's experience with chemical testing over the last year was also reviewe No deficiencies were identified in this are .,
. 14-9. Unit 1 Refueling Activities 9.1 In-Core Instrumentation Thimble Tube Wear The incore neutron flux instrumentation system at Unit 1 consists of 50 incore axial flux thimble tubes and five associated movable neu-tron flux detectors. The fixed thimble tubes are inserted into the reactor through conduits which extend from the bottom of the reactor vessel up into the thimble seal table inside the Containment Build-ing. The thimble tubes serve as the primary boundary for the reactor coolant system. They are externally exposed to high pressure reactor coolant and are internally dry for detector passage. Normal reactor coolant system makeup can accommodate a postulated rupture of approx-imately three thimble tube Recent industry experience has identified significant wear (wall loss)
on thimble tubes. In response to this issue, the licensee contracted an outside vendor (Cramer & Lindell Engineers, Inc.) to perform eddy-current testing (ECT) of all 50 thimble tube The ECT results showed that indications on the tube outside diameter (0D) are cate-gorized as follows: 5 with greater than or equal to 40% wall loss (46% maximum), 6 with greater than or equal to 30% wall loss,12 with greater than or equal to 20% wall loss, 23 with greater than or equal to 10% wall loss, and 3 with no indications. Five thimble tubes with OD indications also showed potential inside diameter (ID) indica-tions, however, none of the ID indications were axially aligned with a corresponding OD indicatio .
The results of the ECT were sent to the NSSS vendor (Westinghouse)
to obtain a proposed resolution. Westinghouse recommend 2d that any thimble tubes with indications greater than 45% be capped-off, and thimble tubes with indications greater than or equal to 40% be axially repositioned to move the' wear indication away from its orig-inal impact area. Westinghouse also requested that the licensee per-form a followup inspection during the next refueling outage of all thimble tubes that are either capped-off or axially repositioned so as to measure further tube degradation and monitor wear rates or wear progressio Both the ECT and NSSS vendors performed independent finite element stress analyses for the Unit 1 thimble tubes, and determined that a 60% wall lost over a length of one inch is structurally acceptabl Each thimble tube has an installed manual isolation valv The Westinghouse safety evaluation permits the use of a qualified isola-tion valve as an alternative to cutting the tube and installing a cap. The licensee implemented this alternative for the one thimble tube whose wall loss was 46%. The inspector confirmed that admin-istrative controls have been implemented which alert personnel that the affected thimble tube has been isolate \
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The licensee currently plans to re-examine the Unit 1 thimble tubes that were either isolated or relocate Additional tubes may also be tested during the next refueling outag The licensee and the NSSS vendor are continuing to investigate this phenomenon of thimble tube wall loss, including a root cause determination and the adequacy of this interim fix. The NRC will continue to follow this issue, and it will be reviewed during subsequent inspections and/or correspondenc .2 Tool and Material Controls The inspector reviewed the licensee's tool and material control pro-gram with respect to the restricted access areas inside the Contain-ment and Fuel Building Corrective Maintenance Procedures CMP 1-75-238, Tool Control during Reactor Vessel Refueling, and CMP 1-75-320, Fuel Pool Tool Control during Reactor Vessel Refueling con-tain the governing administrative requirements for the tool and mate-rial control program during refueling operations. CMP 1-75-238 is to be in effect at all times while the reactor vessel head is removed and delineates tool, material and personnel access control responsi-bilities for the restricted access area inside the Ccntainment Build-ing, elevation 767'. CMP 175-320 is to be in effect when the reactor vessel head is removed and both the fuel transfer system weir gate
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and gate valve are open. The inspector routinely toured the affected areas to verify that the requirements as specified in the above pro-cedures were adequately implemented. No deficiencies were noted dur-ing the tour The inspector interviewed licensee personnel and found that there were times (e.g. , during shift change, or radio-graphy exam) that the containment tool control area was not manned by the responsible tool cler This action, however, was compensated for in that the affected restricted area access point was locked closed such that personnel could not freely enter the are The inspector noted that there was an additional entrance to the area, however that door was nailed shut. No safety concerns were iaenti-fied with respect to the licensee's implementation of tool and mate-rial control activities during refueling outag .3 Design Change Package Review The inspector reviewed several outage related design changes that were determined by the licensee not to require approval by the NR Selected Design Change Packages (DCPs) were reviewed to ensure that they have been reviewed and approved in accordance with plant Tech-nical Specifications and 10 CFR 50.59 (Changes, Tests, and Experi-ments) requirement Various phases of the work activities associ-ated with the DCPs, including construction, maintenance and testing, were witnessed by the inspector. The DCPs were also reviewed against the following criteria: changes controlled by approved procedures;
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. 16 test deviations reviewed and retesting accomplished as necessary; operator training programs revised and/or operators instructed regarding the modifications prior to. implementation; controlled draw-ings revised; _ and inservice testing / inspection requirements incor-porated into the appropriate programs as required. The ' following DCPs were reviewed with respect to the above: DCP 740, Class IE Inverter static switches, DCP 750, cooling for the rod control /MG room, cable tray and switchgear rooms, DCP 798, upflow conversion, DCP 808, large bore primary component snubber elimination, DCP 829, BVPS No.1 feedwater system upgrade and DCP 878, thermal shield bolt replacemen Items of concern were brought to the licensee's atten-tion, for resolution or initiation of action to resolve the concer No violations or unresolved items were identifie .4 Feedwater System Piping Cracks Following review of Unit 1 feedwater system radiographic examinations performed during the outage, the licensee identified apparent crack-ing in the counterbore of the feedwater elbow to feedwater water nozzle in all three steam generators (SGs). Supplemental ultrasonic testing performed on some of the indications confirmed the presence of the apparent flaw The licensee performed engineering evalua-tions and determined that the linear indications were not attributed to the geometric configuration of the weld joint preparatio The affected feedwater elbows were subsequently replaced and satisfac-torily examined during the outage. The inspector observed selected portions of the replacement activitie No deficiencies were identifie This problem had previously been identified as a potentially generic concern with Westinghouse SGs. Additionally, this same problem pre-viously occurred at Unit 1 in 1979, when all three feedwater elbows were replace Subsequent to the initial identification of the cracking in 1979, the licensee implemented a periodic radiographic examination schedule for the affected piping. The licensee is at-tributing the latest feedwater elbow cracks to thermal stratification of the 16" main feedwater lines caused by the flow of localized and relatively cold auxiliary feedwater, which created a large thermal gradient in the feedwater pipin The inspector questioned whether measures to prevent a third occurr-ence of the phenomenon had been evaluated and/or implemented. The licensee stated that a resolution had previously been determined, however, the necessary components were not readily availabl The incorporation of a thermal sleeve on each of the feedwater elbows is expected to protect against similar occurrence The licensee plans to continue to inspect these elbows and stated that if this problem reoccurs, the associated corrective repair will include the instal-lation of thermal sleeve ,
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The Unit 2 feedwater system utilizes the thermal sleeve design for the affected elbows, therefore, similar problems are not as likel The Unit 2 inspection requirements are delineated in ASME Section XI, Inservice Inspection Program. Review of the licensee's proposed recommendations for the Unit 1 elbows will be completed during a subsequent inspectio .5 Cycle 6 Fuel Failures During July, 1987, the licensee noted slightly elevated primary sys-tem activity level Normal reactor coolant system (RCS) activity levels during the time prior to July, 1987, averaged about 2.5 E-3 micro Ci/ gram, while the elevated levels from approximately July, 1987 through the end of the cycle (December,1987) averaged about E-3 micro Ci/ gram. The licensee initially suspected baffle jetting as the cause for the apparent failed fuel indications since baffle jetting had occurred during the previous cycle. However, subsequent analyses by the fuel manufacturer (Westinghouse) concluded that baffle jetting had not occurred, however, some fuel rods had failed due to other cause During the sixth refueling outage, the licensee contracted an outside vendor (Babcock & Wilcox - B&W) to inspect all of the fuel assemblies (157) that were used during cycle 6 operation and additional fuel assemblies stored in the plant fuel pool which were not spent. B&W inspected the fuel assemblies, each consisting of a 17 x 17 array of individual fuel rods for the purpose of identifying failed fuel rod The system that was employed for the inspection used an ultrasonic technique. Including confirmation exams, B&W conducted ultrasonic exams of 45,144 fuel rod The ultrasonic exams characterized two individual fuel rods as being failed. Each of the two f ailed fuel rods was associated with a dif-ferent fuel assembl The exams confirmed that baffle jetting was not the cause for the fuel failures. The licensee determined that both f ailed fuel rod indications existed in spent fuel assemblie That is, the fuel assemblies were not planned to be reused in cycle 7, and therefore, no immediate corrective action or reanalysis was required. The damaged fuel rods were internally located on the 17 x 17 assemblies, therefore, would not have been readily detected by
routine visual examinatio The licensee's decision to implement this ultrasonic examination technique was noted as a conservative action. This action helped the licensee to identify fuel failures, which may not have been identified through the normal inspection process and provided assurance that failed fuel would not be rein-serted for another cycl . - . _ , _ - _ _ _ , . - - -
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18 j The licensee previously purchased two failed fuel canisters. During this refueling outage, the previously failed fuel assembly (due to baffle jetting) was placed in one canister and one of the two fuel assemblies containing a failed fuel rod identified this refueling outage, was placed in the other canis.ter. The remaining fuel assem-bly will be stored in the spent fuel pool storage racks. The licen-see purchased the canisters to store severely damaged fuel assemblies as a means to control hot particle contaminatio No deficiencies were identified during the review of this ite .6 Thermal Shield Bolt Replacement During implementation activities associated with Design Change Pack-age (DCP) No. 798, Upflow Conversion, the licensee identified that one of the bolts (of 12 total) that secures the thermal shield to the lower core barrel had severed, and the threaded portion of the bolt was extending through the lower core barre The bolt was subse-quently removed and examined by an offsite vendo The preliminary results indicated transgranular fracture to be the type of failure, however, no fatigue strictions were observed. The examination pre-paration included removing the heavy oxide layer, which may have also removed fatigue striction indication The offsite vendor plans to perform additional examination to further irivestigate the root cause for the failur The licensee developed DCP Ho, 878, Thermal Shield Bolt Replacement,
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to remove and replace the broken bolt in the reactor internal The replacement bolt was manufactured from the same material and was of a similar design, except for the locking mechanism. The inspector monitored portiors of the modification activities, including verify-ing that approved procedures were used for the planned evolutions and appropriate radiological cor.trols' were implemented. The bolt removal and replacement activities were performed under water in the reactor cavity with the core barrel lif ted out of the reactor and rotated such that radiation exposure would be minimized. The licensee con-tracted a team of divers to perform the underwater repair activitie The inspector verified that adequate pre-briefing a. 4 training sessions were conducted prior to performance of the repair The licensee performed ultrasonic testing of the remaining 11 thermal shield bolts to assure that they were intact; no indications were observed, From viewing previous video tapes of prior refueling activities, the licensee determined that a 1984 remote routine inspection of the top former plates recorded a dark object in the
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vicinity of the bol The licensee subsequently determined that the dark object was the damaged bolt. This information indicated that the bolt was broken and in place for at least three to four year No safety concerns have been identifie The inspector will review the results of the vendor failure analysis during a subsequent inspectio .7 Steam Generator U-Tube Inspection Steam Generator (SG) eddy-current testing (ECT) activities were re-viewed by the inspecto The licensee initially planned to inspect 1601 U-tubes on the A SG to meet the selection and inspection re-quirements of Technical Specification 3/4.4.5, Reactor Coolant System Steam Generator However, results of this sample inspection iden-tified approximately 19 U-tubes having greater than 40% thru-wall indication (defective) and required pluggin This placed the SG into the C-3 category of Technical Specification Table 4.4-2, Steam Generator Tube Inspections, which required the licensee to inspect the remaining U-tubes in the "A" SG and all tubes in the remaining two SG The SG inspections consisted of multi-frequency ECT, including the use of a rotating pancake coil (RPC) probe. The RPC probe was used primarily for the U-bend region and for a sample of distorted signal indications (DSIs) from other ECT probes. A DSI is an indication of such a size / voltage that indicates that a defect is present, however, could not be positively quantifie On February 5,1938, the NRC issued NRC Bulletin No. 88-02, Rapidly Propagating Fatigue Cracks in Steam Generator Tubes. The purpose of the bulletin was to request that affected licensees with SGs having carbon steel support plates implement actions to minimize the poten-tial for a steam generator tube rupture event caused by a rapidly propagating fatigue crack such as occurred at North Anna, Unit 1, on July 15, 1987. The licensee's NSSS vendor (Westinghouse) reviewed the ECT data and performed analyses which identified SG tubes that were susceptible to the North Anna Unit 1 type of tube failure. A total of 6 tubes were plugged with leak-lim. ting tube plugs with an orifice like device on the Unit 1 steam generatcrs (1 in "A" SG, 5 in
"C" SG) to limit SG primary to secondary leak rates to less that 300 gpm should such a failure occu Leak limiting plugs were used so that the licensee could identify that this type of tube failure had occurre It is expected that if the associated tubes were plugged by conventional means (and therefore isolated), and the tube had sub-sequently ruptured in the North Anna failure mode, the licensee would not be able to identify that the rupture had occurred and the failed U-tube could act as a whip and damage adjacent U-tube Therefore,
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with the use of leak limiting plugs, such a failure could be iden-tified by noting primary to secondary increase in leakage and a normal controlled shutdown could be initiated. Licensee response to NRC Bulletin 88-02 will be reviewed during a subsequent inspection (50-334/88-BU-02). The inspector reviewed portions of the eddy-current testing activities, including implementation of radiological controls. Final results from the 100% ECT activities of the SGs are as follows: "A" SG-37 tubes plugged, "B" SG-20 tubes plugged, "C" SG-15 tubes plugged. The total number of tubes plugged this outage was 7 The inspector verified that SG U-tube plugging levels as documented in design LOCA analysis, dated July 17, 1986, were not reached. No unresobed items or violations were identitie . Unit 2 Alert Oue to Annunciator Loss 10.1 Annunciator Cabinet Fire The event was initiated by the failure of a voltage-dependent resis-tor (varistor) on an electronic card in an annunciator cabinet at a remote location two levels below the Control Roo The equipment is powered from a non-vital bus through three different rectifiers. The tripping of two of the rectifiers' breakers produced the erratic annunciation witnessed in the Control Room (see Section 4.2.2). The third rectifier was tripped and the small fire was extinguished with CO2 by the operators dispatched to investigat Approximately 30 cards in the area of the fire were removed and six were visibly damage Power was restored and annunciation was regained between
- 10:00 pm and 10:30 pm to all but a few annunciator window NRC inspectors were on site throughout the event and the resident inspec--
tor arrived in the Control Room at about 7:45 p Continuous NRC inspection coverage was maintained throughout the even .2 Emergency Plan Implementation The control room staff recognized that the loss of the annunciators required an evaluation of emergency action levels, and subsequently declared an Alert at 7:20 p.m. due to loss of the annunciators for
greater than five minutes in accordance with the Emergency Pla All required notifications to of f-site agencies, including the NRC, I were performed by approximately 7:31 p.m. The licensee notified the
! emergency response organization, and subsequently activated the Tecnnical Support Center, Operations Support Center and Radiological Operations Center, and placed the Emergency Operations Facility staff l on standb The on-site f acilities were activated at approximately 9:15 The Media Center was not activated; media functions were performed at the Oxford Center.
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Off-site activation also took olace. Beaver and Columbiana Counties fully activated their Emergency Operations Centers. Hancock County staf fed key personnel, with the remainder of their staff on standb Pennsylvania Emergency Management Agency was fully activated. West Virginia and Ohio activated key personnel, with the remainder of their staf f on standb All affected municipalities were placed on standb The event was terminated at approximately 10:45 p.m. with the restor-ation of the annunciator Termination was discussed with, and agreed to, by all affected agencie .3 Event Followup At the time of Alert termination, the licensee had restored all but a few annunciators. The remaining inoperable alarms were those asso-ciated wiin the electronic cards which had been removed from the cabinet for inspection and/or replacemen Six cards were visibly l damaged as were some of their cabinet connections. Full annunciation was restored by February 1, 1988. In the interim, operators kept temporary logs on the parameters monitored by the missing cards. The plant computer screens, the Safety Parameter Display System, and the ha rd-wi red . safety grade Plant Safety Monitoring System were all operable to supplement the indicators which are normally available to the licensed operators such as status lights, gauges and meter Two other nuclear sites experienced loss of annunciation in the ten days following the Beaver Valley, Unit 2 event. The annunciator sys-tems for all three units were provided by the same vendor, Electro Devit's, Inc. of St. Louis, Missour In the other cases, the fires were more extensive and resulted in greater equipment damage. Details of the events, including similarities with Beaver Valley Unit 2, are presented in IE Information Notice 88-05, dated February 12, 198 Licensee long term actions include reviewing ci rcuitry design for possible improvements in protectio Breaker settings and fuse ratings will be examined as will possible design changes to sub-fuse branch circuit Another modification under review involves the installation of smoke detectors internal to the cabinets for earlier detection of small fires.
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10.4 Revision of Emergency Preparedness Plan The declaration of an Alert was consistent with the licensee's Emerg-ency Preparedness (EP) Plan, (Issue 8, Revision 2) which called for an Alert to be declared following a loss of all annunciators sus-tained for greater than five minutes (Tab 17). The Plan required the declaration of a Site Area Emergency if either the annunciator loss was sustained for over 15 minutes with the unit not in cold shutdown or if an uncontrolled transient occurred during the annunciator los The Plan's event classification criteria were not consistent with the guidance provided in NUREG 0654, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants" which recommends Site Area Emerg-ency declaration if all annunciators are lost concurrent with a plant transien NUREG 0654 considers an Alert to be appropriate in response to events which involve an actual or potential substantial degradation of the level of plant safety. The Alert is intended, among other things, to assure that offsite emergency are readily available for such tasks as of fsite radiation monitorin Examples in the NUREG of initiating conditions for Alert are severe loss of fuel cladding, rapid gross failure of one steam generator with loss of offsite power, and any tornado striking the facilit NUREG 0654 considers a Site Area Emergency to involve actual or likely major failures of plant functions needed for the protection of the public. Other examples in tne NUREG of initiating conditions for a Site Area Emergency are a LOCA greater than makeup capacity, loss of of f site power concurrent with loss of onsite AC power for more than 15 minutes, and an earthquake greater than design basis level The significance of the dif ference in wording between the licensee's EP Plan and NUREG 0654 is that if the actual annunciator loss had occurred two hours earlier while the unit was still in Mode 4, then the licensee would have declared a Site Area Emergency. No concur-rent transient would have been required as in the NUREG. The inspec-tor expressed the concern that the existing wording could prematurely exercise of fsite agencies and cause unnecessary alarm. The licensee is currently conducting a major review of all emergency action limits and was able to promptly focus attention on the loss of annunciators section of the EP Plan. The licensee agreed with the inspector's concern, drafted a proposed change, conducted the necessary committee reviews, and implemented the EP Plan revision prior to startu x
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, 23 10.5 Summary The operators promptly identified the erratic behavior of the Control Room annunciators to oe a problem originating in specific remote cabinets, and quickly responded to the correct locatio The fire was immediately identified, extinguished and power secured. The event was accurately assessed in accordance with the EP Plan, an Alert was declared, and the required notifications were made. Annun-ciation was restored in an orderly manner and compensatory measures were established for those annunciators not available. Revisions to the EP Plan reflecting the lessons learned from the Alert were imple-mented before startu ,
The licensee's actions during this event, especially the performance of the operators, are considered to be a notable strengt . Unit 2 Line Freezing Due to Cold Weather The current winter season is the first for Unit 2 since the receipt of its operating licens The installed heat tracing had been checked for oper-ability, but under severe low temperatures (wind chill of -35 F) was not adequate to prevent line freezing for all system .1 Refueling Water Storage Tank (RWST) Level Instruments On January 5,1988, the licensee declared two of the four RWST level indicators inoperable due to freezing of their sensing line The
"B" and "0" channels failed to their low-low setting which inserted a false signal into the ECCS logic that the RWST (ECCS injection phase water source) was empty. Without detection, a safety injection signal would have produced immediate switchover to the Containment sump (which would be dry) and loss of RCS injection. Operator detec-tion of the failure was prompt and the af fected channels were by-passe The licensee was required by the Technical Specifications (TS 3.0.3) to restore at least one channel or be 'n Hot Shutdown (Mode 3) within six hours. The safety concern with only two operable instruments is that a single instrument failure during an accident could defeat ECCS by failing high and preventing switchover to the recirculation mod The sensing lines were heat traced but the installed system was not adequate to prevent line freezing. The licensee applied heat direc-tly to the affected components, enclosed the area (tent) and heated it, and superimposed an additional heat tracing system. The licensee was able to restore the instruments before being required to shut dow Less than an hour af ter the restoration of channels "B" and
"D", Channel "A" failed low but was restored in about two hour __-___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____-_______ _
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. 24 Continued licensee efforts to prevent RWST level indicator sensing lines from freezing were frequently reviewed by the inspector due to the potential interference by scaffolding, tent and blowers with safety equipment such as instrumentation, valves and the RWST itsel No other significant problems were id a tifie .2 Quench Spray Recirculation Line On February 6,1988, the licensee was unable initially to complete a scheduled surveillance test of the "B" Quench Spray (QS) pump due to the recirculation line (back to the RWST) being froze The line involved is heat traced and local pipe temperature indications did not reflect that the line was cold enough for blockage at the sensor location. The licensee warmed the line and was later able to com-plete the tes There were no QS system operability concerns associated with the blecked recirculation line because the system flowpath is directly from the RWST to the Containment spray rings and no recirculation flow is required. The inspector expressed the concern that a similar line blockage might be present in the low Head Safety Injection (LHSI) recirculation lines. The LHSI line size (8 inches) is similar to the QS recirculation line (6 inches) and both are located in the same are The LHSI local line temperature was not low, but the frozen QS line also had not been low according to the local indica-tion. The LHSI recirculation line is required for system operabil-ity; following a LOCA, the LHSI pumps could be damaged by inadequate recirculation flow prior to RCS pressure decreasing sufficiently to allow injectio Af ter discussion with the inspector, the licensee elected to confirm the LHSI recirculation flow path by starting each pump and checking for recirculation flow. The testing was completed satisfactorily prior to entering Mode 3 on February 9,198 . Calibration Program During routine system walkdowns, the in:pector noted that several differ-ent kinds of calibration stickers were present on installed equipmen In some instances (e.g., airborne radiation monitors) different component parts of the same piece of equipment had different kinds of calibration stickers on them. Some stickers indicated the component was beyond the calibration due date and other stickers' calibration due date block was blan _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __
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. 25 The inspector met with members of the st tion staff including the I&C supervisor and QA operations director to discuss the calibration program and the role of the QA Department. The licensee stated that those com-ponents required by TS to be calibrated within a specific period receive a red foil-type sticker with a clearly marked due date. Certain components which are used to measure the performance of other TS required equipment are also given a red foil-type sticker. The licensee explained that the other stickers are not in the TS and include acceptance testing and non-safety equipmen Certain red foil-type stickers were found by the inspector which appeared to indicate that the components were beyond their calibration due dat The components beyond their calibration due date were still within the normal 25'i grace perio These examples were provided to the licensee along with information requests involving certain specific components which apparently were not in the calibration program, but which perhaps should be. The licensee had not yet responded to the examples and requests at the end of this inspection perio The inspector will continue to review this area during the next inspection perio Allegation on Document Control In October, 1987, the inspec'or received an anonymous allegation concern-ing "loop drawings," The . i.di v i dua l alleged that these drawings were uncontrolled but nonetheless had been used in previous years to assemble hardware in the field. The alleger wc.s unable to provide examples or any other specific information, but stated further calls would be mad The inspector was able to identify one dccument type called a "test loop dia-gram" that had not previously been a controlled document, but was unable to identify any instances where that document had been issued to or used by construction groups. The documents show circuit functional information and the licensee had these documents reissued as controlled documents around April 1987, for use by the operating staff. No further contact was made by the allege No deficiencies were identifie . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 (Reporting Requirements) are reviewe The review assessed whether the reported information was valid, included the NRC required data and whether results and supporting information were consis-tent with design p.edictions and performance specifications. The inspec-tor also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed:
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BV1/BV2 Monthly Operating Report for Plant Operations from December 1-31, 198 BV1/BV2 Monthly Operating Report for Plant Operations from January 1-31, 198 BV1 Special Report, submitted in accordance with Technical Specifica-tion 3.7.15.a (Fire Rated Assemblies) requirement No deficiencies were note . Inoffice Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC Region I office to verify that the det311s of the event were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event war-ranted onsite followu The following LERs were reviewed:
Unit 1 LER 87-19-00: Radiation Monitor Failure Caused Main Filter Bank Ventila-tion Alignmen LER 87-20-00: Energization of Containment Purge Exhaust Monitor Results in ESF Actuatio LER 87-21-00: Inoperable Charcoal Filter Bank Sprinkler Nozzle Unit _2 LER 88-01-00: 2/4 Refueling Water Storage Tank Low Level Channels Inoperabl The above LERs were reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 102 Previous inspection reports had identified certain weaknesses in the preparation and complete-ness of LERs. Recent inspection reports had noted that good event analyses, root cause determinations and corrective actions implementation were documented in subsequent LER The LERs reviewed during this period were also good with the exception of LER 87-21-00 on Unit $'
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. 27 Unit 1 has experienced repetitive clogging of filter bank sprinkler nozzles as documented in LER 86-05-00, 86-05-01 and 86-05-02. Each LER revision presented additional discoveries of cle'.a ed nozzles despite sub-stantial licensee efforts tc identify and cort act the root caus The current discovery of nozzle clogging came during tests which were conduc-ted earlier than normal as part of the corrective actions discussed in the earlier LER. LER 87-21-00 does not address the schedule for similar tests in the future; the discovery of nozzle clogging within the already short-ened cycle indicates a need for continued testing on an accelerated basi The LER does not propose corrective actions which address the root cause except for a reference to a design change under consideration, yet no future supplenental report is proposed. Degradation in the ability to extinguish a fire in the filter banks has been chronic since initial dis-covery on June 21, 1986, during a tri-annual tes Safety analyses have been limited to noting the presence of a redundant filter bank and have not addressed the possible effects of an unquenched fire involving poten-tially contaminated charcoa For the above reasons, LER 87-21-00 on Unit 1 is considered weak. Licen-see senior management acknowledged the inspector's concerns and stated that a supplemental report would be submitted to LER 87-21-0 The inspector will continue to review LERs in future inspection . Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with the licensee at the conclusion of the report period on February 19. 1988.