IR 05000282/1993014
| ML20057E794 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 10/01/1993 |
| From: | Kobetz T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20057E787 | List: |
| References | |
| 50-282-93-14, 50-282-93014, NUDOCS 9310130157 | |
| Download: ML20057E794 (31) | |
Text
{{#Wiki_filter:. . U.S. NL: LEAR RESUL T0;.( C;MMISSION
REGION III
, Reports No. 50-282/93014(CRP): 50-306.93C14(DRP) Docket Nos. 50-282: 50-306 License Nos. DPR-42; DPR-60 l Licensee: Northern States Power Company , 414 Nicollet Mall Minneapolis, MN 55401 ! Facility Name: Prairie Islana Nuclear Generating Plant , Inspection At: Prairie Island Site. Red Wing, u.N Inspection Conductec: Julj 20 througr. Sectembe - 13, 1993 Inspectors: M. L. Capas C. N. Cesini R. L.
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r - hw} f',4cfmiM - Approved By:. imoth Koce:z. actir,g C+1ief M ~O /'b Reactc-Pre;ects Sectior 2A Date , i Inspection Summary Inspection on July 20 through September 13, 1993 (Reports No. 50-282/93014(DRP): 50-305/93014(DR?)) Areas Inscected: Routine. unannounced inspection by resident and regional inspectors of plant :perational safety including onsite followup of events, maintenance, surveil'ance. engineering and technical support, radiological controls, licensee f:llcwup on previously identified items, licensee event report followup, and followup on regicnal requests.
! l 9310130157 931001 PDR ADDCK 05000282 G l pyg
.. . - _ - _ _ , i Executive Summary , Enforcement One non-cited violation of NRC requirements, one unresolved item, and one inspection followup item were identified in the areas inspected.
Operations ! One non-cited violation was identified regarding the testing of an emergency ! diesel generator while an opposite train engineered safety features component was out-of-service for preventive maintenance (paragraph 7.d).
One inspection followup item was identified regarding the failure of selected components in the load sequencer for 4 kV safeguards bus No.15 (paragraph 1.b).
Licensee , corrective actions to address records falsification issues identified during previous inspections were adequate (paragraph 6). Relative to Prairie Island, this closes a long-standing, unresolved item associated with generic resolution of an NRC concern with falsification of records at numerous nuclear power plants. A strength was identified in the licensee's resolution of numerous charging pump deficiencies (paragraph 1.c).
Maintenance and Surveillance l No new strengths or weaknesses were identified. The licensee's actions to address bolt failures associated with emergency diesel generator support ] equipment were thorough and demonstrated a positive safety perspective ' (paragraph 2.a).
, Enoineerino and Technical Support One unresolved item was identified regarding high energy line breaks and associated steam exclusion system boundaries (paragraph 4.a).
A notice of enforcement discretion was granted when the licensee determined that a temporary penetration seal did not provide adequate protection for a 4 kV safeguards bus room from steam Jet impingement following a postulated main steam line break (paragraph 4.b).
Plant Support
No new strengths or weaknesses were identified. Two reportable events
occurred in the area of radiological controls (paragraph 5).
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._ _ __ _ __ _ i i ' t f DETAILS L 1.
Doerational Safety Verification (71707. 93702) , i The inspectors observed control room operations, reviewed applicable j logs, conducted discussions with control room operators, and observed i shift turnovers.
The inspectors verified operability of selected emergency systems, reviewed equipment control records, verified the , proper return to service of affected components, and conducted tours of the auxiliary building, turbine building and external areas of the plant , to observe plant equipment conditions, including potential. fire hazards, l and to verify that maintenance work requests had been initiated for equipment in need of repairs.
! a.
General l Both units operated at full power throughout the inspection period except as noted below.
- ' Unit I was reduced in power for turbine valve testing and condenser cleaning on August 15, 1993.
Eleven condenser waterbox manway gaskets were also replaced during these activities.
Upon
refilling the condenser, two waterbox manway gaskets failed, which ' required securing a circulating water pump to replace the gaskets.
After gasket replacement and during the power increase, the No.11 main feedwater (MFW) pump locked out when an attempt was made to ' start it. An electrical fault in the pump motor stator caused the lockout.
A spare stator was available onsite and repair efforts l were initiated.
With only one MFW pump available, power was i limited to approximately 62 percent.
On August 18, another condenser waterbox manway gasket failed and power was reduced to about 35 percent to allow a circulating water pump to be secured and the gasket to be replaced.
All repairs to the No. 11 MFW pump i and condenser were completed on August 18 and Unit I was returned to full power.
On August 22, another power reduction was required after a fourth condenser manway gasket failure. The gasket was replaced and Unit I was restored to full power on August 23.
No further condenser manway gasket problems occurred during the inspection period.
The inspectors discussed the gasket failures with the responsible system engineer.
The system engineer informed the inspectors that there had been no change in the supplier or the type of gasket procured since initial plant startup. The gaskets , are made of conventional molded rubber, and the licensee has I occasionally experienced gasket failures in the past.
The licensee has reviewed the recent failures to determine possible causes.
This effort has also included sending both a failed gasket and a new gasket offsite for testing. The licensee has determined that one potential cause for the failure is that the amount of torque or torque sequence applied to manway cover bolts !
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_ -- . - _ during installation could cause gasket cutting.
The licensee intends to experiment with different gasket installation techniques during the upcoming Unit 1 outage and plans to develop
installation guidance for maintenance personnel.
The inspectors considered the licensee's actions to address the increased , incidence of gasket failures adequate, and noted that the licensee l was proactive in its approach to resolving this.
b.
Bus 15 Load Seauencer Failure While on a routine plant tour on September 5, 1993, at approximately 6:30 p.m., an auxiliary plant operator (AP0) noted ! that the programmable logic controller (PLC) indicator light on ! the load sequencer for Unit 14 kV safeguards bus No.15, located in the No. 15 bus room, was continuously lit.
The PLC status light normally flashes on and off during standby conditions and is an indicator that the load sequencer is ready for safeguards service.
No control room alarm is received for this condition to promptly alert the control room operators of a load sequencer problem.
However, AP0s are trained to observe the condition of i the PLC status light during their tours of the bus room while onshift. At most, the condition existed several hours.
When the condition was identified, the licensee declared bus 15 inoperable and entered an 8-hour technical specification (TS) limiting ' condition for operation (LCO) action statement.
With the load sequencer in a degraded condition, if a safety injection signal or bus undervoltage condition occurred, then emergency diesel generator (EDG) D1 may not have been capable of supplying power to train A engineered safety features (ESF) loads due to improper load sequencer operation.
The licensee initiated an emergency work request to repair the load sequencer. As safeguards bus No. 15 was not impaired in any way due to the inoperable load sequencer (a concern existed only if D1 attempted to assume ESF loads), the licensee decided to place the control switch for the D1 EDG in " pull-out," thereby preventing the diesel from operating.
The licensee then exited _, the 8-hour LC0 action statement for bus 15 inoperability and . entered a 7-day LC0 action statement for having D1 inoperable.
The inspectors considered that this was an appropriate action because bus 15 could be supplied by either of two offsite a.c.
power sources or by the Unit 2 alternate a.c. source: 4 kV bus i No. 25.
Also, the opposite train of Unit 1 ESF equipment was ' operable (including 4 kV bus 16 and EDG D2).
The licensee called l in a system engineer and electricians to troubleshoot and repair the load sequencer.
The required parts were available onsite and i the load sequencer was returned to service within 6 hours of the ' original identification. The inspectors considered the off-hours i response and repair efforts a strength.
, i l The load sequencers for the four safeguards 4 kV buses at Prairie Island are new, digital components, placed in service following
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i the dual unit outage in January 1993. The inspectors consider the relatively rapid failure of the load sequencer components to be ' unusual and will follow up on the licensee's determination of the cause of the failure, and any proposed corrective or compensatory actions, in a future inspection (Inspection Followup Item t 282/93014-01:306/93014-01).
, ! c.
Unit 1 Charoina Pump Issues
During both this inspection period and the previous inspection periods, several Unit I charging pump problems have occurred.
The - inspectors discussed charging pump issues with the responsible system engineer and members of the operations and maintenance departments.
Some of the Unit I charging pump events that have recently - occurred are: (1) July 15, 1993: Overload trip on No.12 charging pump due to . motor lead short (discussed in NRC Inspection Report r 282/93010;306/93010).
The licensee recommended inspecting and retaping motor leads on all other charging pumps to help . prever.t vibration-induced wear resulting in other shorts.
(2) July 27, 1993: Motor stator fault on No.13 charging pump.
This fault caused copper splatter in the motor control center (MCC) breaker cubicle.
The licensee decided that-it would move No.13 charging pump motor supply breaker to a spare cubicle in the MCC and displayed a cautious safety attitude in its work planning process, considering what operational impact could occur with respect to other equipment powered from the same MCC.
(3) July 25, 1993: Premature failure of No. 12 charging pump drive belts.
Belt procurement requirements were changed to ensure that matched sets of pump belts are purchased and installed during periodic belt replacement.
(4) August 17, 1993: Speed control troubleshooting of No.13 charging pump and lifting of No.11 charging pump discharge relief valve.
Operators had requested to troubleshoot No. 13 charging pump's speed controller due to observed oscillations in charging flow and reactor coolant pump (RCP) seal injection flow when No.13 charging pump was in l service.
During one portion of the troubleshooting activities (when No. 11 charging pump was in service and i l No. 12 charging pump was out-of service for breaker I maintenance), I&C personnel requested.that No.13 charging pump be started. When No. 13 pump was started, the " charging line high pressure" control room annunciator was received, charging line flow decreased, and RCP seal injection flow decreased.
Suspecting that No. 13 charging
._ _ , pump discharge relief valve had lifted, control room operators secured No. 13 pump. This action resulted in charging and seal injection flow decreasing to zero, indicating that it was actually No. 11 charging pump discharge relief valve which had lifted.
The operators secured No.11 pump and restored charging flow with No.13 pump.
Later, No. 12 charging pump was returned to service and I&C personnel rebuilt No. 13 pump's speed controller positioner.
The No. 11 pump discharge relief valve was removed, tested, and rebuilt.
Tests of the relief valve confirmed that its pressure setpoint was correct. The licensee determined after reviewing plant process computer data and conducting interviews with operators that the most probable cause for the relief valve lifting was that the charging pump header pressure was slightly too high with the No. 11 pump running to accommodate the additional pressure increase when the No. 13 pump was started. The licensee planned to implement an operations procedure change to provide additional guidance to operators regarding reducing charging header pressure when placing a second charging pump in service.
(5) August 25, 1993: Leakage from No. 13 charging pump due to cracked seat valve. This issue is discussed in paragraph 2.b.
In their review the inspectors were not able to substantiate or identify any significant programmatic deficiencies with regard to charging pump maintenance or operation.
Rather, the inspectors observed strong performance by personnel in engineering, mechanical and electrical maintenance, and instrumentation and controls (I&C) disciplines in resolving charging pump issues. Also, the inspectors noted strengths in the licensee's maintenance evaluation process for improving component reliability.
d.
Securina Both Trains of a Safety-Related Ventilation System The D5/D6 building is a recently constructed, Seismic Category I building which houses the new Unit 2 emergency diesel generators (EDGs) and associated Class IE electrical distribution equipment for Unit 2 engineered safety features loads.
Safeguards electrical equipment areas of the building, including the 4160 Volt bus rooms, 480 Volt bus rooms, and EDG local control rooms, are provided with a " safety-related emergency equipment switchgear areas ventilation system," referred to as the D5/06 building.
heating, ventilation, and air conditioning (HVAC) system.
Each train of D5/D6 building HVAC provides ventilation for one train of safeguards equipment.
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, j During the week of July 12, 1993, the licensee noted that filter - material debris was being distributed throughout the electrical i equipment areas of the D5/06 building from the ductwork of the
HVAC system. A work request was initiated to address this > problem.
At 12:45 a.m. on July 19, 1993, both trains of the D5/D6 building HVAC system were secured. The HVAC system was returned to service at 4:05 p.m. on July 19.
' The NRC performed a special safety inspection to review this event.
The results of that inspection are documented in NRC Inspection Report 50-306/93015 (DRP). This report discusses the details of the event and addresses regulatory compliance issues
related to the securing of both trains of the DS/D6 building HVAC system for approximately 15% hours.
e.
Fitness-For-Duty Test On August 2,1993, the licensee informed the inspectors that a NRC-licensed reactor operator had been administered a random .' alcohol breathalyzer test and had tested positive. A positive result was also obtained from a confirmatory alcohol breathalyzer test. A subsequent blood alcohol test, requested by the operator,
confirmed the breathalyzer test result. After testing positive on ! the breathalyzer, the operator was escorted from the protected
area and his site access badge was deactivated. The operator had
been on shift for approximately 4 hours before the random fitness-for-duty test was administered. The licensee reviewed all activities' that involved the reactor operator while he was onshift and concluded that the operator did not take any actions that
could have jeopardized plant safety..The inspectors informed NRC l Region III management of this fitness-for-duty event.
The results > of the NRC's review and follow up of this event are addressed in i separate correspondence between the NRC and the licensed operator.
, One inspection followup item was identified.
No violations, deviations, or unresolved items were identified.
r 2.
Maintenance Observation (71707. 37700. 62703) i Routine preventive and corrective maintenance activities were observed ! to ascertain that they were conducted in accordance with approved l procedures, regulatory guides, industry codes or standards, and in conformance with Technical Specifications.
The following items were.
considered during this review: adherence to Limiting Conditions for Operation while components or systems were removed from service, l approvals were obtained prior to initiating the work, activities were accomplished using approved procedures and were inspected as applicable,
functional testing and/or calibrations were performed prior to returning , components or systems to service, quality control records were , t
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- - - - . - I maintained, activities were accomplished by qualified personnel, , radiological controls were implemented, and fire prevention controls l were implemented.
Portions of the following maintenance activities were observed or reviewed during the inspection period, a.
Replacement of D2 Turbocharaers The inspectors observed portions of a planned replacement of the turbochargers on D2 EDG.
D2 was out of service from August 23, > 1993, until completion of a post-maintenance test on August 26; approximately half of the outage time allowed by the technical i specifications.
The inspectors also discussed the purpose of the < ' turbocharger replacement project with the responsible system engineer.
The system engineer explained that as part of an EDG ! performance trending program, turbocharger performance.had been , observed to be declining. This was indicated by trending cylinder exhaust temperature and scavenging air pressure data collected during monthly surveillance tests. The licensee stated that there
was no question that D2 was still capable of performing its intended safety function, however, to improve engine performance, the licensee determined it would be prudent to replace the turbochargers.
The inspectors also discussed with the licensee its timing of performing a major EDG maintenance activity while having both reactor units at power versus waiting until the next > Unit I refueling outage. The licensee informed the inspectors that since the addition of EDGs D5 and 06 as dedicated EDGs for ' Unit 2, allowing the original EDGs D1 and D2 to be dedicated to Unit 1 instead of being shared as safeguards power sources between the units, performance of an EDG maintenance activity while at power provided no significant increase in risk. The licensee also
informed the inspectors that it did, however, take a precaution of delaying this non-essential EDG maintenance activity until the annual severe storm / tornado season had passed.
This reduced the probability of a storm-induced loss of offsite power when the EDG was inoperable.
. During the turbocharger replacement, the licensee observed that two out of six turbocharger support bolts for one of the turbochargers were broken. Also, both bolts on a blower discharge ' piping support bracket were broken.
The licensee initiated a nonconforming item report and determined that the root cause for_- the blower discharge pipe support bracket bolt failures was probably due to vibration. The apparent root causes of failure , for the turbocharger support bolts were overtightening for one ' bolt and excessive strain fatigue due to repeated exhaust piping disassembly / reassembly.
The licensee replaced the failed bolts with higher strength bolts and will periodically inspect the . bolting for any failures. The licensee evaluated the bolt ' failures for 10 CFR Part 21 reportability and determined that the ) failures did not comprise a substantial safety hazard at Prairie I
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- - - - i ! i ! ! Island. This decision was based on an analysis of bolt stress
response to the design basis earthquake (DBE) acceleration spectra i that confirmed that the EDG would still be capable of performing , its intended safety function.
The licensee forwarded a letter reporting its findings to the EDG vendor for consideration at other facilities which might have more severe DBE acceleration spectra.
The inspectors concluded that the licensee's actions were thorough and demonstrated a positive safety perspective.
, b.
Repair of No. 13 Charaina Pump Leak , The inspectors observed maintenance activities to investigate and ! repair a leak on No. 13 charging pump.
Upon disassembly of the l pump it was evident that the leak was due to a cracked seat valve.
In order to ensure that the cracked seat valve was the only cause of leakage, an informational penetrant test was performed on the ,
l area of the block where the valve is seated. This test revealed minor pitting due to corrosion.
However, the licensee determined
l that the corrosion did not interfere with the seating surfaces, and would not cause further leakage. The seat valve was replaced, and the pump was reassembled.
Subsequent to the reassembly, post-maintenance testing revealed that the pump had a desurger problem.
Although pump operation is possible with a failed desurger, this is not an optimal configuration and the licensee decided to proceed with repair.
Following desurger repair, the pump was successfully returned to service.
, No violations, deviations, unresolved items, or inspection followup items were identified.
j 3.
Surveillance (37700, 61726, 71707)
The inspectors reviewed Technical Specification required surveillance testing as described below, and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, and Limiting Conditions for Operation were met.
The inspectors further verified that the removal and restoration of affected components were properly accomplished, test results conformed with Technical Specifications and procedure requirements, test results were reviewed by personnel other than the individual directing the test,_ and deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
Portions of the following test activities were observed or reviewed: i ' a.
SP 1307. "D2 Diesel Generator Fast Start Test" The inspectors observed the performance of portions of surveillance procedure SP 1307 "D2 Diesel Generator Fast Start l Test" on August 26, 1993.
SP 1307 requires the diesel to be run for 4 hours.
During the first hour, the inspector made three significant observations:
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1) Exhaust was leaking from several places into the diesel generator room.
A small fire ignited at one of these
locations lasting for 2 or 3 minutes.
, 2) A " Fuel Oil Level Low Day Tank" alarm was received due to fuel oil transfer pump No. 124 failing to auto-start.
- . 3) An " Exhaust Stack Temperature High" alarm was received.
For approximately the first hour that th? diesel was running, there was exhaust leaking from several joints in the exhaust piping. At the joint that connects the exhaust header to the turbocharger inlet, flames ignited and burned for about 2 to 3 minutes. The flames were approximately 4 inches high. The responsible system engineer monitored the flames to ensure that they were not impacting diesel operability.
The flames diminished i and the fire extinguished itself after 3 minutes.
The inspectors noted at about 3 hours into the surveillance that there was no evidence of the earlier exhaust leaks. Discussions with the system engineer clarified that typically, as the exhaust components heat up, the resulting thermal expansion tightens connections, which reduces exhaust leakage.
The engineer also stated that the joint where flames ignited will have a new gasket installed during the next diesel preventive maintenance outage, scheduled to occur within the next month.
A " Fuel Oil Level Low Day Tank" alarm was received during the first hour.
In response to this alarm, the operator checked the fuel oil transfer system line-up and noticed that No.124 fuel oil transfer pump, which should have started automatically, was not running. The operator then positioned the auto select switch to No. 123 fuel oil transfer pump, which automatically started and refilled the day tank. The licensee later identified that No. 124 pump would operate when its selector switch was in the " manual" > position. A work request was written in response to its failure to autostart.
, ' b.
SP 2035A. " Reactor Protection Loaic Test At Power" , On July 19, 1993, during the performance of surveillance procedure SP 2035A, two NBFD relays failed. The subject relays were installed in the Unit 2 reactor protection logic system on September 20, 1990.
Both relays are normally energized.
For the subject surveillance test, the relays are de-energized, change of contact state is verified, and the relays are then re-energized.
Testing of the relay logic channels is performed on a per train basis using vendor designed test circuitry. On July 19, several minutes after testing the 2RT-7/8 logic matrices associated with the Intermediate Range High Flux Block circuitry, an acrid odor was noticed by the instrumentation and controls (I&C) technician performing the surveillance test. The odor appeared to emanate from relay 21RB-2XA, however, this relay was still functioning
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I properly. Upon further investigation, the I&C technician
identified an open coil winding on relay 2RT-8XA.
Power to the logic system was isolated and relay 2RT-8XA replaced. Upon
reenergization of the logic circuitry, relay 21RB-2XA failed with
' smoke visually emanating from the relay coil An open was found , in the relay coil winding and the relay was replaced. The entire
logic train was then retested.
No other problems were noted.
! The licensee initiated a nonconforming item report (NIR) for the . failed relays.
The relays were returned to the vendor i (Westinghouse) for failure analysis. The licensee requested the vendor to evaluate the failure mode, the apparent root cause for the failures, whether the failure was an isolated case or reflected a potential generic problem, and whether a 10 CFR Part
21 notification was required.
, Upon receipt of the relays, the vendor conducted a. visual examination. The vendor observed that relay 2IRB-2XA was missing one contact, had a visibly bulged area approximately 1/4-inch wide around the circumference of the coil, had a large crack in the , coil case, and had a large amount of potting compound on the ~ outside of the coil case.
Relay 2RT-8XA had an approximate 1 inch vertical crack in a bulged area of the coil case with some potting compound outside the crack.
The vendor conducted electrical continuity testing on the relay coils and then subjected the coils to oven testing.
Based on the visual examination of the coils and
the oven test results, the vendor concluded that the subject coils ^ were manufactured with potting compound that was not' homogeneous 1y , mixed.
This resulted in domains in the coils where the ! composition of the potting material was markedly different than l the normally expected compound. The coil case bulges and coil t conductor openings were most likely caused by overheating and deficient potting compound expansion. The vendor suggested that the overheating was probably caused by one or more of the
following: a) extended overvoltages, b) lack of cooling or air circulation, c) breakdown of the winding conductor varnish insulation, or d) poor winding or manufacturing practices.
The non-homogeneous potting compound issue had been previously addressed in o Part 21 notification by Westinghouse in June 1991.
In this notification, Westinghouse provided recommended actions to determine if NBFD relays that contained the deficient potting compound were acceptable for. continued use in various plant applications.
For NBFD relays that were currently installed, I Wostinghouse stated that no action was needed if the relays had performed properly after two surveillance test cycles.
In response to the Part 21 notification, the licensee replaced all Unit 1 NBFD relays and heat tested NBFD relays in stock.
The Unit 2 relays were not replaced since the acceptance criteria for identifying an operational problem with installed relays had been satisfied.
In their failure analysis report dated August 'll, 1993, Westinghouse concluded that the July 19, 1993 NBFD relay
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. failures due to overheating were a " random type" of failure within the context of the previously identified potting compound issue.
'. Westinghouse stated that this conclusion was based on the fact that each relay was manufactured at a different time and from a different lot, and no similar type failure had been reported via the Nuclear Product Reliability Data System since resolution of the original Part 21 issue. Westinghouse also stated that the existing commercial dedication instruction (CDI) requires an oven . check of the coil potting compound as part of the dedication , process.
Following receipt of the Westinghouse failure analysis report, the licensee requested the vendor to provide additional information on the basis for some of the conclusions discussed in the report.
Specifically, the licensee asked what criteria was used to determine that the NBFD relay failures at Prairie Island were " random," noting that the subject relays were procured prior to ' the vendor's determination that the dedication process should incorporate the CDI guidance.
The licensee also questioned why ' ' the recent relay failures fall outside the realm of the previous 10 CFR Part 21 report relative to the potting compound issue. The licensee further noted that the subject relays were deemed acceptable per guidance provided by Westinghouse in the original Part 21 report, and questioned _the validity of the acceptance criteria for determining that specific relays that contained the deficient potting compound were acceptable for continued use in plant applications.
Following subsequent discussion with the vendor to address these specific questions, the licensee concluded that the subject relay failures were random and, therefore,- not reportable under Part 21. The licensee concluded that the overheating of the relays was most likely caused by a breakdown of the winding conductor varnish insulation and/or poor winding or manufacturing practices. The licensee also stated that a visual inspection of all NBFD relays installed in the Unit 2 reactor
protection system would be conducted the next time that SP 2035A l is performed.
The inspectors reviewed the correspondence between the vendor and the licensee related to this issue, including the failure analysis report. The inspectors also discussed with the licensee the . ! additional information provided by the vendor to address those questions raised by the licensee following its review of the failure analysis report. The licensee stated that the vendor j conducted a detailed investigation into the potting compound issue l when it was originally identified in 1991.
Based on the results . of this investigation, the vendor concluded that a deficiency in j the potting compound manufacturing process (a sticking check i valve) caused the non-homogeneity in the compound. The vendor i replaced the defective check valve and determined which specific lots of potting compound had been manufactured while the defective check valve had been installed. The potting compound used in the two NBFD relays that failed at Prairie Island did come from a lot
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i , ! manufactured while the defective check valve was in place.
However, the vendor stated that the acceptance criteria in the original Part 21 notification for determining if relays that contained a non-homogeneous potting compound were acceptable for continued use in various plant applications, was valid. The acceptability for continued use was based on relay operation in a normal environment.
The criteria did not address overheating.
The vendor concluded that the failures which resulted in relay overheating were random and did not reflect a generic problem.
The vendor maintained that the original issue with deficient
potting compound had been adequately addressed in the June 1991 , Part 21 notification.
The inspectors will review the results of the Unit 2, NBFD relay inspection that the licensee plans to-perform during the next SP 2035A surveillance test.
No violations, deviations, unresolved items or inspection followup items were identified.
l ' 4.
Enaineerina and Technical Support (37700. 40500. 71707) a.
Hiah Enerav Line Break (HELB) and Steam Exclusion Issues During this inspection period, the licensee identified a potentially safety significant issue with respect to a postulated HELB outside of containment. The issue involves the protection of
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equipment that is not environmentally qualified to operate in " harsh," post-HELB conditions, but which is necessary to mitigate the consequences of a HELB.
A discussion of postulated HELB accidents and the Prairie Island facility's design for protection against the consequences of these accidents are presented in the licensee's Updated Safety Analysis Report (USAR), Appendix 1, " Postulated Pipe Failure Analysis Outside of Containment." High energy lines are defined as those
systems having a service temperature greater than 200 degrees Fahrenheit and a design pressure greater than 275 psig.
, These conditions apply to the main steam, feedwater, steam , generator blowdown, and chemical and volume control systems, and to the turbine-driven auxiliary feedwater pump steam supply. The USAR contains analyses of a postulated break or crack in piping for each of the above referenced systems, describes design featur es in place for reducing the impact of breaks at the locations of highest stress (design basis break), and defines the equipment required to be protected from the effects of a break or
crack in order to bring the plant to a safe shutdown' condition.
, In 1990, the licensee proposed a modification (No. 90L188, Rev. 2) to install a new recirculation line for the containment spray. (CS) pumps for both units from CS pump discharge to the refueling water storage tank (RWST). The modification would eliminate the CS l pumps from sharing the same recirculation line used by the safety injection (SI) pumps.
In 1993, the licensee proposed a i i
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modification.(No. 93L389) to install flow indicating equipment in i CS pump recirculation lines in order to support ASME Code Section i XI inservice testing requirements for the plant's third, 10-year l ' testing interval. The licensee proposed to install this modification in conjunction with the installation of the new CS i pump recirculation piping.
The CS pumps are located on the 695' floor of the auxiliary
building and the new recirculation piping is designed to enter the concrete wall of the RWST at approximately the 770' elevation of the auxiliary building.
Therefo're, the licensee planned to drill l holes through the 715', 735', and 755' floors to provide a path .! for the new pipe. The licensee-initiated work request No. U3312- -l CS-Q to drill the necessary holes in the auxiliary building floors and the RWST wall to prepare for pipe installation and completion of the modifications during the next Unit 1 outage. The penetration in the 715' floor was completed on August 6,1993.
On August 25, 1993, a member of the licensee's staff observed ' these penetrations while on a tour of the auxiliary building and questioned whether these penetrations resulted in a breach of any required barriers, e.g., a tire zone or auxiliary building special ventilation (ABSV) zone bount'ary.
Further discussions among the ! licensee's staff identified tiat fire protection and ABSV zone ! requirements had been accounted for, however, the licensee + _ identified that the penetration in the 715' floor comprised a ' breach in a steam exclusi a boundary separating the 695' and 715' floors of the auxiliary buiMing.
Following the discovery that
j the 715' flenr was a steam exclusion boundary, the licensee ' l initiated immediate actions to seal the opening.
The penetration i was sealed on August 25, witnin 6 hours of identifying that the
floor was a steam exclusion bonndary.
Subsequently, the - inspectors verified by measuremant that the surface area of the penetration in the concrete RWST wall, part of the ABSV zone
boundary, was less than 0.1 ft" and therefore, was not required to be sealed or logged open, per.the licensee's procedures.
Steam exclusion boundaries are not explicitly addressed in the technical specifications, only in the USAR. However, technical specification (TS) 3.4.C does provide limiting conditions for > operation and action statements for the steam exclusion system.
, The steam exclusion system consists of pairs of ventilation i dampers in series within ventilation ducts between areas which may l experience the effects of a HELB and areas that contain equipment ' needed for accident mitigation but not environmentally qualified i to withstand the effects of a HELB.
The steam exclusion system ! actuation circuitry closes the dampers in response to high i temperature sensed by resistance temperature detectors located between the dampers.
l The inspectors attended a meeting of the Operations Committee (OC) i on August 30, 1993, at which the licensee presented a draft TS
i
! ! , - . . . . .
_.- , interpretation for review which would have expanded the scope of TS 3.4.C to include any penetration in a steam exclusion boundary
and allow such penetrations to be open under administrative control for up to 24 hours. TS 3.4.C allows one channel of the steam exclusion system to be inoperable for up to 24 hours, however, if both channels are inoperable, both dampers in the j associated ventilation duct must be manually closed within 4 hours.
In essence, TS 3.4.C allows an opening, analogous to a , hole, to exist in a steam exclusion boundary for 4 hours. The OC did not approve the subject TS interpretation.
! Following the August 30th OC meeting, the inspectors consulted with an environmental qualification (EQ) specialist in the NRC Region III office for guidance in the area of EQ, reviewed the ' 7 USAR Appendix 1, and reviewed the configuration / layout of - equipment defined in the USAR Appendix I as required for mitigation of a HELB. The SI pumps are located on the 695'
elevation of the auxiliary building, in the vicinity immediately i , l below the subject penetration in the 715' floor. The main steam
' line from No.12 steam generator exits the Unit I shield building in the same " compartment" on the 715' elevation that the floor ! penetration to the 695' elevation is located. The USAR Appendix I , lists the SI pumps (and associated suction valves, power sources, , l and controls) as required equipment for mitigating the . . consequences of a HELB. Additionally, the USAR states that the SI ' , pumps will be isolated from the postulated accident environment, l and that the compartment in which these pumps are located is - protected from any effect of a steam line break originating in any other compartment.
Concurrent with the inspectors' review of this EQ issue, the
licensee evaluated what effect a HELB would have had on the environment in the vicinity of the SI pumps, given the existence - of a 6 by 6 inch hole in the 715' floor. The inspectors attended ~ ! a meeting of the OC on September 3,1993, at which the licensee reviewed an Issue Resolution Form and calculation defining the l consequences of a main steam line break (MSLB), coincident with the condition of an open penetration in the steam exclusion boundary. The results of the calculation indicated that the 695' elevation would have become a harsh environment had a MSLB occurred. The DC concluded that since the 695' elevation was assumed to be a mild environment following a HELB, this condition ' placed the plant in a condition outside of its design basis and as a result, a 1-hour NRC notification was required per 10 CFR 50.72.
Following the conclusion of the inspection period, the ' licensee completed a more rigorous calculation, although final review was not complete, demonstrating that the environment in the SI pump area would not have affected SI pump operability following a MSLB.
However, the licensee stated it did not intend to retract its l event notification.
l I . --.---- - m -- y - y ,_yyy-- gg , ,,y - -w9 r rp-y g-s.--y
, -i
, Following the determination of event reportability by the OC, the , licensee immediately began implementing several followup actions, - including: issuing a standing order to heighten awareness of existing steam exclusion boundaries and to ensure that their integrity was maintained, initiating a walkdown of the 715' ' elevation to identify and seal any additional open penetrations to the 695' elevation, and initiating a review of open work requests to prevent any new steam exclusion boundary openings. The
licensee's search for additional breaches of steam exclusion ' boundaries was very aggressive. Through the end of the inspection period, the licensee had identified more than 20 openings in - various boundaries. Many of_these have existed since the plant , was built.
Some were located in areas where there was not an obvious steam transmission path to the 695' elevation from areas
subject to a harsh, post-HELB environment.
For example, openings [ were identified in the valve galleries, waste. gas compressor r rooms, chemical and volume control system holdup tank areas, as well as letdown and ' steam generator blowdown flash tank areas.. , Upon identification, openings in steam exclusion boundaries were l sealed with penetration sealing material-. Many of the searco, , identification, and sealing efforts occurred during the Labor Day holiday. The licensee's ability to mobilize people on a holiday
weekend to facilitate prompt identification and sealing of steam exclusion boundary openings was considered a strength.
The licensee established a multidisciplinary " steam exclusion issue task force" to prepare and carry out a project plan for resolution of steam exclusion issues.
For example, efforts were initiated to hire outside consultants with additional expertise in this area to assist licensee staff in quantifying the significance of the as-found condition of steam exclusion boundary openings, t and developing strategies for demonstrating the acceptability of
creating openings in a steam exclusion boundary for modifications.
' The inspectors attended several meetings of the task force and
concluded that they were effective forums for planning new action items and providing status updates on item resolution.
I One of the task force's action items was to discuss steam j exclusion issues with the NRC. A conference call was conducted ) ' with the licensee on September 8,1993, with technical staff and i supervisors from the regional office and the Office of Nuclear Reactor Regulation participating.
During this conference call, the NRC staff learned more about the complications the licensee . faces with respect to the plant-specific arrangement of equipment, l and protection of this equipment from the effects of a HELB when j the licensee needs to make openings in a barrier to support modification activities. As the example of the 715' floor penetration demonstrated, since the 695' elevation is defined to be a mild post-HELB environment, redundant trains of safeguards equipment are not contained within individual " steam intrusion- '
l l - . . - _- _ ,. _ -.,
-- - _ l proof" rooms. Therefore, single failure protection of equipment i on the 695' elevation is not assured if the environment becomes
j harsh.
i Additionally, the 695' elevation has a steam communication path l between Unit I and Unit 2 areas. Therefore, inter-unit effects of i a HELB cannot be ignored, even if one unit is shut down. At the , i conclusion of the conference call, the inspectors discussed with i the licensee the relevant contents of generic NRC communications i ' regarding EQ issues and associated operability determinations.
These communications principally address the case where the l environmental qualification of equipment designed to operate in a l , harsh environment is called into question.
Whereas, in the case
of the penetration in the 715' elevation, equipment that is not !
designed to operate in a harsh environment, specifically the SI pumps, could have been subjected to a harsh environment in the l event of a HELB, potentially rendering this equipment inoperable.
In either case, a prompt equipment operability determination is l required.
i i At the conclusion of the inspection period, the licensee was ' continuing its efforts through'the steam excrusion task force to complete its search for additional breaches in' the steam exclusion ' boundary and its evaluation of the safety significance of the as-found conditions if a HELB occurred.
The inspectars considered ' the issue of identification of steam exclusion boundary openings l to be an unresolved item pending further review of the licensee's , actions and evaluation of the potential safety significance - i (Unresolved Item 282/93014-02; 306/93014-02).
j I b.
Notice of Enforcement Discretion In addition to searching for and sealing existing openings in i steam exclusion boundaries, the licensee initiated an effort to
review the adequacy of existing permanent and temporary penetration seals in steam exclusion boundaries.
In particular, i two temporary penetration seals were reviewed by the inspectors and the licensee during this inspection period.
Penetration No.
2609 was recently created in the safety-related wall between 4 kV l safeguards bus No. 16 and the Unit I turbine building.
, Penetration No. 2610 was recently created in the safety-related J wall between the Unit I turbine building and the 715' elevation of ~ the auxiliary building. These penetrations were made to support ' the licensee's ongoing station blackout / electrical safeguards upgrade (SB0/ESU) project, in order to provide a path for the installation of new safety related cables that will provide safeguards power from new 480 V safeguards buses to existing . ! train B safeguards motor control centers.
Both penetrations were - !
rectangular in shape, approximately 2 ft" in area.
After the penetrations were created in the concrete walls, they
were filled with fire resistant wool, covered on both sides with '
i i i I ' ._ _ __ - _ _ _ .
~ i i b [ , thermal board, and coated with fire resistant material.
Nine
cables were then pulled one at a time through holes made in the ' penetration thermal boards, specifically, from the new Unit 1
train B 480 V bus rooms, through bus room No. 16, into the turbine building through penetration No. 2609, and into the auxiliary . building through penetration No. 2610. All of this work occurred before August 26, 1993, when the original-steam exclusion issue (discussed in paragraph 4.a) was identified. At the conclusion of the inspection period, permanent seals had not been installed on
these penetrations.
On September 10 and 13, 1993, the inspectors discussed with the licensee the adequacy of these temporary penetration seals with respect to steam exclusion, fire zone, and auxiliary building special ventilation (ABSV) zone boundary requirements. The inspectors observed that on the. auxiliary-building side of penetration No. 2610, air was entering the auxiliary building through the annular spaces around the cables passing through the l penetration's wool and thermal boards.
Since the 715' elevation of the auxiliary building is not considered a post-HELB mild environment, penetration No. 2610 is not required to function as a i steam exclusion barrier.
However, the inspectors were concerned about the penetration's fire zone and ABSV zone boundary requirements.
The licensee stated that the seal for penetration
No. 2610 was adequate for ABSV zone requirements because the total t penetration area that existed in the annular spaces around the cables was less than 0.1 ft"; and therefore was not required to be i accounted for as a loggable ABSV zone boundary opening.
The
licensee inserted additional wool around the cable for both ! penetrations and stated that for penetration No. 2609, it was l reviewing the requirements for penetration integrity as a steam
exclusion boundary. The inspectors also discussed with a licensee ' EQ engineer the consequences of a MSLB in the turbine building.
The engineer informed the inspectors that the turbine building could be considered an " infinite volume" and as such, a post-HELB ambient pressure increase would be minimal.
However, the dynamic < l pressure effects of steam jet impingement are not negligible in locations near the MSLB. The inspectors discussed with the engineer that the location of penetration No. 2609 relative to the location of the nearest main steam line design basis break point, as indicated in the USAR, may have an impact on the integrity of the penetration seal due to steam jet impingement dynamic pressure forces.
The licensee continued its review of this issue and determined that a MSLB at the design basis break point nearest to penetration i No. 2609 could result in a steam jet impinging upon the penetration seal with a dynamic pressure in excess of 20 psi.
This would result in a breech of the steam exclusion boundary and allow steam to enter the bus 16 room. The safeguards buses are not environmentally qualified to operate in a harsh, post-HELB environment. Therefore, the licensee declared bus 16 inoperable .
- - - - - - - - - - - - - - --
. _ .--.. -. \\ l at 5:15 pm on September 13, 1993, and entered an 8-hour TS limiting condition for operation (LCO) action statement. The licensee requested a notice of enforcement discretion (N0ED) from the NRC to extend the action statement time by an additional 16 hours. This LC0 extension was requested by the licensee to allow installation of portions of a previously designed and fabricated steam impingement barrier which would protect penetration No. 2609 from the effects of a HELB. The NRC verbally granted this N0ED at approximately 8:30 p.m. on September 13, 1993, and the licensee proceeded with installation of the steam impingement barrier. The licensee completed its installation of , the portions of the barrier necessary to protect penetration No.
j 2609 on September 14, 1993, and declared bus 16 operable at approximately 11:30 a.m.
The inspectors concluded that the licensee's declaration that 4 kV. safeguards bus No.16 was j inoperable because of the potential for this bus to be subjected to a harsh environment, was appropriate.
One unresolved item was identified. No violations, deviations, or ) inspection followup items were identified.
, i 5.
Radiolooical Controls (71707) On September 8,1993, the licensee informed the inspectors that it had ) determined that an analysis of radioactive effluent required by the j Offsite Dose Calculation Manual (0DCM) had not been performed in I August 1993 for effluent data for the month of July..The results of l this analysis are used to set alarm and trip setpoints for effluent monitoring instrumentation channels.
Also, the analysis is used to
confirm that appropriate radioactive waste handling equipment is being used. An analysis was performed in September using data collected during July and data collected during August which confirmed that the i instrumentation alarm and trip setpoints had been set appropriately since the last time the analysis was performed (July 1993 using data from June 1993) and that appropriate radioactive waste handling equipment was in service. The licensee determined that this event was reportable per 10 CFR 50.73 and plans to issue an LER.
The LER will be referred to a regional radiation protection specialist for review and followup.
On September 10, 1993, the licensee informed the inspectors that it had determined that due to a miscommunication between the operations department and the radiochemistry department, a reconfiguration in operation of the auxiliary building ventilation system was performed and an accompanying reconfiguration in the gaseous effluent monitoring. system for tritium was not performed. This resulted in a condition where gaseous effluent from the auxiliary building was not being continuously monitored for tritium. The condition existed for ' approximately 2 days before it was corrected.
The licensee reviewed i operational data for that time frame and determined that there were no
abnormal transients that would have resulted in any unexpected effluent release. The licensee determined that this event was reportable per
. _ _ _ _ _ _ _ - _ - _ - 10 CFR 50.73 and plans to issue an LER. The LER will.be referred to a regional radiation protection specialist for followup.
No violations, deviations, unresolved items, or inspection followup ' items were identified.
6.
Licensee Followup on Previously Identified Items (92701) (Closed) Unresolved Item 50-282/92015-02: 50-306/92015-02(DRP): During March 1992, The Public Service Company of New Hampshire reported to the NRC that an internal audit at the Seabrook Station identified a number , of operator logs that contained incomplete or inaccurate information recorded by several licensed and non-licensed operators.
Such plant . ! logs are typically used by the facility management as a tool to identify potential problems in need of corrective action.
Information Notice
92-30, " Falsification of Plant Records," was subsequently issued on , April 23, 1992, to alert reactor licensees to the NRC's concern that , plant mechanics, technicians, and operators may have falsified plant i logs at several nuclear power plants. As a result of this information ' notice, most licensees initiated audits to compare their security department's computerized keycard entry records against the plant locations where operators were required to conduct tours. On May 29, 1992, the NRC issued Temporary Instruction (TI) 2515/115,
" Verification of Plant Records," to provide NRC inspectors guidsace for , evaluating each licensee's ability to obtain complete and accurate log readings from both licensed and non-licensad operators.
The inspectors performed the inspection outlined in TI 2515/115 and documented the results in NRC Inspection Report 60-282/92015(DRP); 50-306/92015(DRP). The inspectors identified the.t a required room entry had not been made for each of two safety-related bus rooms. The licensee required these rooms to be inspected twice each shift (four times each day) for malfunctioning equipment and the accumulation of combustible material. The licensee has a written commitment to the NRC to check these rooms at least once a day for combustible material.
No log readings are required to be taken in these rooms.
It appeared that one operator missed both rooms on one of his tours.
The inspectors also identified a records verification issue associated with the documentation of required scaffolding inspections.
This issue is discussed in NRC Inspection Report 50-282/92015(DRP); 50-306/92015(DRP). The NRC requested the licensee to investigate the > scaffolding issue and report the results of its investigation to the NRC. The licensee reported the results of its investigation in a letter dated October 22, 1992, and provided a supplemental response in a letter dated November 2, 1992. The inspectors reviewed the results of the licensee's investigation, discussed the results with the licensee, and documented their review in NRC Inspection Report 50-282/92021(DRP); 50-306/92021(DRP). The licensee verified that scaffold inspection records had been falsified by one individual.
The inspectors determined
., ._ _ -
- = . - ... i l
that the scaffolding inspection record was not an NRC-required record and that the corrective actions to address this issue discussed in the October 22, 1992, letter, were adequate.
j In addition, the licensee identified a significant case of records falsification by chemistry technicians.
Daily total-halogen sampling
from effluent of the plant circulating water discharge had been falsified by several chemistry technicians. The inspectors concluded i that halogen chemistry sampling was not a regulated activity and that the corrective actions to address this issue discussed in the October 22.
and November 2 letters, were adequate.
Finally, the licensee checked security records for 400 required vital area entries' covering a 9-day period in January 1992. Two instances of diissed vital area room inspections by non-licensed operators were found.
The licensee concluded that poor logging practices contributed to these missed room inspections. One practice was to document that a room check had been completed based on the knowledge that another individual had performed the actual room inspection.
The form used to log the room inspections lists in a vertical column each room that is required to be , checked. The other type of poor logging practice was to initial the. log ' sheet in the top space of each column and then draw a line down through the remaining spaces 'in the respective column. This practice provides no positive indication of which vital. area rooms have already been i checked and which rooms still need to be checked.
One of the non-licensed operators that missed a vital area check received a verbal ! warning (the first step in the licensee's positive discipline program).
i The other operator received decision making leave (the third step in the i licensee's positive discipline program).
In response to the records falsification problems identified during its . ; investigation, the licensee committed to conduct followup monitoring over a six-month period to ensure its corrective actions to address these problems were effective.
In a letter dated May 19, 1993, the licensee reported to the NRC that no additional problems had been identified during this six month monitoring period.
j Title 10 of the Code of Federal Regulations (10 CFR) Part 50.9, " Completeness and accuracy of information," requires that information maintained by the licensee pursuant to Commission regulations, orders, or licensee conditions be complete and accurate in.all material respects.
Part 50.5 of 10 CFR, " Deliberate misconduct," provides that the NRC may take enforcement action against an individual including an unlicensed person, who (1) deliberately causes or, but for detection, would have caused a licensee to be in violation of the Commission's requirements; or (2) deliberately provides information to the licensee concerning licensed activities knowing that the information is incomplete or inaccurate in some respect material to the NRC. The NRC expects each licensee to ensure that all of the records that it maintains are complete and accurate. The NRC expects licensees to ensure that logging activities are being properly conducted.
Logging violations in the ' future may result not only in enforcement action '
. .
! t t ! against licensees, but also in direct enforcement action against the individual involved in deliberate record falsification, whether the e ! individual is licensed or not, and whether the individual is a licensee employee or a contractor.
l ' The inspectors concluded that the licensee's corrective actions to address identified records falsification issues were adequate. This item is closed.
7.
Licensee Event Report (LER) Followup (92700. 90712. 92701) { a.
(Closed) LER 282/91005. Revision 2: One pressurizer safety valve - j lift setpoint found 2.5 percent low during test.
Previously, pressurizer safety valves had been set using nitrogen.
As a i result uf NRC Information Notice 89-90, " Pressurizer Safety Valve ' Lift Setpoint Shift," and guidance in Westinghouse WCAP-12910, the , licensee decided to begin testing these valves with steam.
! Revision 0 of this LER discussed the testing of spare pressurizer i code safety valves. One valve that had originally been installed on Unit I lifted at a pressure 2.5 percent lower than its nominal setpoint when-tested with steam.
Later, revision l'was submitted
when a licensee contractor tested the-two valves that had been removed from the Unit 1 pressurizer during the Summer 1991 refueling outage. The valves lifted at 2.6 and 1.16 percent lower than their nominal setpoints.
TS 3.1.A.2.b requires that the i
j valves be set within plus or minus 1 percent of their nominal , i setpoints. Revisions 0 and I were closed,.and a non-cited i ' violation was issued in Inspection Report No. 50-282/92021(DRP).
Revision 2 was issued when a Unit 2 pressurizer safety valve was removed and tested during the Spring 1992 refueling outage and , lifted 2.21 percent below its nominal setting. This completes the testing of all six pressurizer safety valves, two -installed in each unit and two spares, with steam. All-future testing of these j valves will be performed using steam. This LER is closed.
I b.
(Closed) LER 282/93008: Containment isolation valve failed closed due to solenoid valve failure. At 3:57 a.m. (CDT) on June 24, 1993, containment isolation valve CV-31740, Instrument Air to Unit 1 Containment, closed due to failure of its associated solenoid valve, SV-33281. The loss of instrument air to the ' l Unit I containment resulted in the closure of the letdown l isolation and letdown orifice isolation valves in the chemical and volume control system, closure of the cooling water valves to the i control rod drive mechanism cooling system, and realignment of the , ! containment fan coil unit (FCU) discharge dampers to the dome position. This event is discussed in detail in NRC Inspection Report 50-282/93010(DRP); 50-306/93010(DRP). During this event, the licensee entered the shutdown action statement of Technical Specification (TS) 3.6. A.2.
Entry into a TS shutdown action statement is considered operating in a condition prohibited by the plant's TS which requires submittal of an LER.
'
l d i
i i l , Upon noting that CV-31740 was closed, operators attempted to ' reopen the valve from the control room. When this was i unseccessful, the valve was reopened locally to restore instrument air to containment and thus avoid a shutdown transient due to high reactor coolant pump stator temperatures. A dedicated operator was stationed at CV-31740 to manually close this valve should the i need arise. The licensee expedited repair activities.
The inspeccors concluded that the licensee took prudent action to restore instrument air to containment and avoid a shutdown transient.
This LER is closed.
c.
(Closed) LER 282/93009: Unplanned closure of a letdown isolation valve (a containment isolation valve) due to trip of the operating charging pump. This event is discussed in detail in NRC Inspection Report 50-282/93010(DRP); 50-306/93010(DRP).
The reportability aspects of this event are also discussed in the referenced NRC inspection report.
The letdown orifice isolation valves function as containment isolation valves.
The containment isolation system is an engineered safety features (ESF) system.
Closure of one or more containment isolation valves, resulting from either a valid or invalid actuation signal, is considered an ESF actuation.
Invalid actuation signals include signals that
originate from non-ESF circuitry. The letdown system orifice isolation valves are interlocked with the charging pumps. At.
least one charging pump must be running in order to open one of these valves.
In the case of the July 15, 1993, event, trip of the only operating charging pump resulted in loss of the open < permissive signal and closure of the orifice isolation valve.
Closure of this containment isolation valve, an ESF actuation, resulted from a signal generated in non-ESF circuitry. The licensee determined that this event required submittal of a LER , and is revising its administrative procedures to more clearly ' define reportability criteria relative to containment isolation valve closures. This LER is closed.
j d.
(Closed) LER 282/93010: Control room air handler out-of-service i while surveillance testing of a diesel generator was in progress.
At 12:08 a.m. on July 29,1993, No.121 control room air handler , was removed from service for preventive maintenance, rendering Train A of the control room special ventilation system (CRSVS) J inoperable. With one train of the CRSVS inoperable, the licensee entered a 7-day limiting condition for operation (LCO) per Technical Specification (TS) 3.13. A.2.
A six month surveillance test, SP 1307, "D2 Diesel Generator Fast Start Test," was scheduled to be performed on July 29. On the morning of July 29, the Unit 2 shift supervisor was approached for approval to conduct SP 1037. The surveillance procedure requires the shift supervisor to verify that the D1 emergency diesel generator (EDG) and i associated engineered safety features (ESF) equipment are operable before beginning the test on the D2 EDG, since D2 is considered inoperable during the test.
It is the licensee's practice to consider an EDG inoperable when it is paralleled to the grid
i _ . __
during the performance of a surveillance test.
This practice is based on the potential for a grid disturbance to result in a lockout of the EDG while safeguards loads are being sequenced on to the respective safeguards bus during an accident response. The shift supervisor reviewed the LC0 log and apparently misread the entry regarding No.121 control room air handler.
The shift supervisor thought the entry applied to No. 121 control room chiller, which is not considered ESF equipment.
At 8:00 a.m. with' the commencement of SP 1037, the licensee logged the D2 EDG inoperable.
D2 was returned to service at 1:15 p.m.
Shortly after completing SP 1037, the licensee identified that from 8:00 a.m. to 11:26 a.m. both D2 EDG and No. 121 control room air handler had been inoperable.
During the weekly planning meeting that the licensee conducts to schedule the following week's work activities, the licensee reviews maintenance and testing activities that require LC0 entries. The preventive maintenance outage of No. 121 control room air handler was not discussed at the weekly planning meeting and therefore, was not scheduled on the weekly work plan which is provided to the control room.
The licensee's corrective action to prevent recurrence for this event, as described in the LER, was to discuss the event with those individuals involved.
In addition, the licensee will revise the diesel generator surveillance procedures to aid operators in determining operability of associated ESF equipment. The licensee intends to revise its administrative procedures for voluntary entry into LCOs, for example, to support non-scheduled maintenance and testing activities, to insure adequate management approval is obtained prior to making any LC0 entries.
The inspectors will evaluate the adequacy of the licensee's corrective action during a future inspection.
TS 3.7.B.1 states that, "One diesel generator may be inoperable for 7 days provided... (b) all engineered safety features equipment associated with the operable diesel generator is-OPERABLE,...." Having both D2 EDG and No. 121 control room air handler inoperable from 8:00 a.m. until 11:26 a.m. on July 29, 1993, is considered a violation of TS 3.7.B.1.
During this time period, there was no safeguards demand for either the CRSVS or the D2 EDG. While the CRSVS did not meet single failure criteria during this 3%-hour period, Train B of the CRSVS was available. Although the D2 EDG is declared inoperable during surveillance testing based on the potential for a grid disturbance to cause a diesel lockout (a low probability event), D2 was available to assume safeguards loads in response to a demand. The inspectors concluded that the violation was of minor safety significance.
l .
As described above, the licensee's actions appeared to be in violation of NRC requirements.
However, the violation is not being cited because the criteria specified in'Section VII.B.2 of the " General Statement of Policy and Procedure for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C), were satisfied.
One non-cited violation was identified.
No deviations, unresolved items or inspection followup items were identified.
8.
Followup on Reaional Reauests (2500/028. 71707) a.
Emplovee Concerns Proarams The Energy Reorganization Act, Section 211, and 10 CFR 50.7 prohibits employers from discriminating against employees for taking actions to initiate NRC proceedings or otherwise raise safety issues to the NRC or licensees. An issue being assessed by the NRC staff is whether the NRC should encourage or require licensees to implement an employee concerns program to encourage employees to come forward without fear of retribution.
To aid in this effort, the inspectors were requested to complete Temporary Instruction (TI) 2500/028, " Employee Concerns Program." The TI consisted of a survey, which the inspectors completed during discussions with the licensee. A copy of the completed survey is attached to this inspection report.
b.
Boraflex Dearadation in Spent Fuel Pool Racks The inspectors received a technical issue summary from the Region III office regarding the observed degradation of Boraflex neutron-absorption material used in the spent fuel pool storage racks at another nuclear plant. Test coupons of the Boraflex material that were removed during the first 5-year surveillance of the material showed that substantial degradation had occurred.
The inspectors discussed this event with the licensee and its applicability at Prairie Island.
Boraflex is used in the spent fuel pool racks at Prairie Island as one of the diverse means to ensure subcriticality in the spent fuel pool. The licensee installed the Boraflex in 1982 and has already retrieved surveillance coupons for testing on two separate occasions.
Although there was evidence of some small amount of shrinkage, no significant material degradation was observed.
The next surveillance coupon to be tested is scheduled for removal from the spent fuel pool in February 1994.
No violations, deviations, unresolved items or inspection followup items were identified.
- . l ! t
9.
Unresolved Items ! ! Unresolved items are matters about which more information is required in i order to ascertain whether they are acceptable items, violations, or
deviations.
An unresolved item is discussed in paragraph 4.a.
i ! 10.
Inspection Followuo Items , Inspection followup items involve activities which were not completed within the inspection period, where additional inspection is necessary
and planned.
An inspection followup item is discussed in paragraph 1.b.
11.
Manaaement Interview (71707) ! t The inspectors met with the licensee representatives denoted in paragraph 12 after the conclusion of the report period on September 17, 1993. The inspectors discussed the purpose and scope of the inspection and the findings. The inspectors also discussed the likely information content of the inspection report with regard'to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any documents or processes as proprietary.
' 12.
Persons Contacted
l
- E. Watzl, General Manager, Prairie Island
- M. Wadley, Plant Manager
- K. Albrecht, General Superintendent, Engineering
- G. Lenertz,' General Superintendent, Maintenance
- D. Schuelke, General Superintendent, Radiation Protection
, and Chemistry J. Sorenson, General Superintendent of Plant Operations M. Reddemann, General Superintendent, Electrical and i Instrumentation Systems
- G. Rolfson, General Superintendent, Engineering i
G. Miller, Superintendent, Technical Support ! J. Mcdonald, Superintendent, Site Quality Assurance
- A. Hunstad, Staff Engineer
- J. Hill, Superintendent, Instrumentation and Controls i
' Systems
- J. Maki, Superintendent, Electrical Systems
- P. Ryan, Shift Manager
. J. Hoffman, Senior Consultant Engineer
- R. Mella, Production Engineer M. Thompson, Project Engineer S. Hiedeman, Production Engineer P. Braaten, Production Engineer E. Ballou, Production Engineer
, I E. Eckholt, Nuclear Support Services
- J. Leveille, Nuclear Support Services l
- G. Aandahl, Superintendent Design Standards l
' l
i
- M. Dapas, NRC Senior Resident Inspector
- R. Bywater, NRC Resident inspector C. Orsini, NRC Reactor Engineer
- Denotes those present at the management interview of September 17, 1993.
ATTACHMENT: Employee Concerns Programs
.- - ' . Attachment , . DIPLOYEE CONCERNS PROGEMS ACRTHtMJ PLANT NAME:bijbEMDLICENSEErFTA71's PawsRDOCKET f: D e'?f3', 68-38f NOTE: Please circle yes or no if appilcable and add coments in the space " provided.
A.
PROGRAM: . 1.
Ooththe licensee have an employee concerns program? No/Coments) - 80-aTaf3el4]So*J06[f50g 2.
Has NRC inLs acted the program? Report # w w, rx. . B.
SCOPE: (Circle all that apply)
1.
Is it for: ~ a.
Technt ? No/Coments) b.
Administrative? s No/Coments) - is c.
Personnel ssues? No/ Comments) 2.
D , It cover safety as well as non-safety issues? . > g No/Coments) ' Ye.S '
3.
Is it designed for l s.
Nuclear safety? No/Coopents) f-5 b.
Personal safety? (Yes, kComents) { , No,ksandsakty cacuss wL ctportsk k %. sift Ssis c.
Personne' issues - including union grievances? D'f"f M b (Yes E Comments) M YO 4.
O the program ap ly to all licensee employees? gr No/ Comments Ys 5.
Contractors? otNo/ Comments) , 0.6 . 15stle Date: 07/29/93 A] 2500/020 Attachment P0 "d alls at+f1SI 318106.3 ~kf 4 EP:PT E6/60/60
_ _ _. __ __ . " ., . J 6.
Does the licensee require its contractors and their subs to have a , similar g.pgram? . (Yesgrgfj'coments) g . a 7.
Does the licensee conduct an exit interview upon terminating . yees asking if they have any safety concerns? e . at No/ Comments) , , it.$ C.
INDEPENDENCE: 1.
What is the title of the person in charge? . hufarIaI8M #f ikt kJA$!h 2.
Who do they report to?
' Th'ete 4w, tJackar go. lit bepathwad
, ' 3.
Are they independent of line' management? Yt.5 - 4.
Does the ECP use third party consultants? g Q {. Ye+,4.sce.sscg.
e-- +w3
5.
How is a concern about a manager or vice president followed up? L Tht.rt)6 no da.El4td. grootst '66 pl ct. MEW.f, k h[gli Mh D.
RESOURCES: #N'N ** A I'88 h M%
- f fUd% sence'88 af M me M t.
1.
What is the size of the staff devoted to this program? ~Tha.rt are 'll ytopit.'r %t. Sitt QA organizdien $1 art Aed:tss'ible ag part
What are ECP staff qualifications (technical tra*nin
2.
. interviewing training. Investigator training, other)g.
All,$ Ka. Ec.P s440 kava. M audi4p& ' asp.c.% " bioing.. . E.
REFERRAL.5: . 1.
Who has followup on concerns (ECP staff, line management.
W 32.cP datG makfa.A respens%)ih for fellesey ef
noi'ft.ftretA 'ke f ank liat. m n4 p ng4k.
C*ncten s, d*actr*5 art l F.
CONFIDENTIALITY: 1.
Are the r > orts confidential? (Yes ' Comments) hp.~Qn. iWky af k inAN & regerk a catcLen Is t'00-
inrJ J M (~ a g ra p ert M E c f s h f f Iss u u. b ever, Altag cewrio et et *ialiwdud's, caneern 4 acP5kfS m im e, re.perf, d"odJttsting yks.e44ctra 4=J. ach'ns faken 4o d$aftJ o N A-2 Isstle Date: 07/29/93 2500/028 Attachment E0 *d 311S Q 7f151 31titutki "Rf4 IP:PI E6/60/60 . . .. .l
- - _ _
i. ! ' i ! I .
2.
Who is the identity of the alleger nade known to (senior management, . ECP staff, line management, other)? (circle, if other explain) , Q g*gjg* sh 44dt A{{Gjti" sa da:Y A$h'dd k ner m4J.e. ke,= b e ag ne. ev&d A4. of 14. ser 34.ff.
3.
Can empicyees be: j . a.' An'onymous? No/ Comments) . ' l b.
Report by phone? No/ Comments)- YC5. A h.le.f eae.
hef llaa % 8 5 In44n 8 8EAkI1 N 'J h*f4.
h G.
FEEDBACK: A.* **ym ou$ et.f erf 6 #^ ^'t 44. M'd4 VIA ffdefM.
1.
feedback given to the alleger upon completion of the followup? , ' n No - If so, how?) e.5,"I'$ 4Ac.'iA4 4*h** d $n. cancun Mll preddg, Mbsek, Sinff sol'io rtetsve
- 4g l
-)h4. E.C f8 , i 2.
Does program reward good ideas? d 88l* e 8 8 II*a. Ne f4ut.- frejra n 'is ne f mt4nt fo 64. An "iden ke+l'4[ j 3.
Who, or at what level, makes the final decision of resolution? Tgyic. Ally 4 h h. Sierdtendtat *I 3Ge Qual *h, 4.
Are the resolutions of anonymous concerns disseminated?
Ye.s. TuocW.n er surv<ittaau raerts oc ~ ~es 9 s 64 k 4 = A#$e,s.htA dtP*.f4 stA1I's. . 5.
Are resolutions of valid concerns pubilcized (newsletter, i , bulletin board, all hands meeting, other)7
O 11.
EFFECTIVENESS: 1.
Ilow does the licensee measure the effectiveness of the program? No guan+NA4lw measurt for progr4m effectlW.Ms.5 ha6 be4.n EshklisAed, j One Possikt<. me.4kel of measureme4t may laa. h numby ef' concoces 2.
.Are concerns: reesive4 by %e.afge, Trended? h g No/ Comments) - a.
' Yt$. Csnaeres rt. golf s 'ss acneeskensass3 gre, entsee j k4e % s.
rY/Yo'a#neIt[ - b.
Use YES, deaceras (Acofif,(A q form basis fw-etce@44heng,( a L71 V 3.
In the last three years how many concerns were raised 7 Of the concersn raised, how many were closed? What percentage were substantiated? .g g f, g4g,,c, ,gg 1% pes,.cn 6 4 p'n Mee M.ve. ket ahoof Wr-cens ratead, At\\ c..uras reedn4 act e.ventun&j c.l.sta Reoghh bee-4
Aru.- few&s of Mut. ce *cteas We.e4. Soks4*aba4 4, Issue (late: 07/29/93 A-3 2500/028 Attachment E0 *d 311S Ottfl51 3. '1108d Mf 4 TP:PT E6/60/GO - . -. . - -,, -.
e' ,. - .
4.
Ilow are followup techniques used to sneasure effectiveness
(random survey, interviews, other)? Tits persen ac 'sa.<n+;bd k unccros istMceview<4.
. 5.
Itow frequently are internal audits of the ECP conducted and by whom? g,gy,,g 9 gey yy,,, gg been pg,.f,,,,j,
- . I.
ADMINISTRATION / TRAINING: - Is ECP prescribed by a procedure? (Yes athonements) 1.
g,.n.,.erga,. u e _ a +* a aea,a.
2.
liow are employees, as well as contractors, made aware of this program (training. newsletter, bulletin board, other)? A nc+hs. b cylvs} eon +ra s+<rs is yestcu *n hvit<.+,*n besees near Ma. Mt.c. Fec-3 Also, %= Wu.*PresiA4.,d, NucJese 6e er.t,4 ide.H fys' h istence of 44.
l Seaf a meme 4e tl emplepasProscae an A ft.14Aene, nu= 6tes to c.K.y '*laa ($ *ls* ye Tr s ADDITIONAL COMENTs (Includlng characteristics which make the progree j especially effective, if any.)
Taf ytA, Pla,dhf,'yQ { Io li h u g,, lur5 A{$o F4 W id M d a l Ty (ped'. uG u A:.:Ard % 94.k u 4, g., , j paa A A f.c*p%=.s1.nr.e4c+-u<<b-4 7 4, A g Ares of Sa4% N* e-hrb4-ec, }{.*wktug Jy.g uA ' Mai: %.; %%. or4. eresaa u.cx,, w r oig_ e; t4s> f.enr.t.en. ' 'TLt. Is c5** 555 k5. dIf.o t%Nt4M da Errer RJue]/o= Tis k Teret.
, . Y'N * I t.t.t My Isfare., %44 ER,TF f f{nsh . C.veds or "ne4r m($s[ an4 Ka ERrp p'[( ca J.uc t ,a, ideg tsk of % c.0c m tiances, , , NAME: TITLE: Pil0NE f: "I* s bwde.f / M Adert 3"nu./ 6f t/598 8209 OATE COMPLETED d]!9.f94 g i .
. 2500/028 Attachment A-4 Issue Date: 07/29/93 T0 *d 311S OtWlSI Blditfdd Dtf4 OP:tri E6/60/60 0020 88C ET9 }}