IR 05000305/2004022
| ML17291A814 | |
| Person / Time | |
|---|---|
| Site: | Columbia, Kewaunee  |
| Issue date: | 05/15/1995 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17291A812 | List: |
| References | |
| 50-397-95-09, 50-397-95-9, NUDOCS 9505260050 | |
| Download: ML17291A814 (26) | |
Text
ENCLOSURE
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-397/95-09 License:
NPF-21 Licensee:
Washington Public Power Supply System 3000 George Washington Way P.O.
Box 968, MD 1023 Richland, Washington Facility Name:
Washington Nuclear Project-2 (WNP-2)
Inspection At; WNP-2 site near Richland, Washington Inspection Conducted:
March 5 through April 22, 1995 Inspectors:
R.
C. Barr, Senior Resident Inspector D. L. Proulx, Resident Inspector D.
E. Corporandy, Project Inspector Approved: D..
C am er ain, Acting C ie, rogect Branc Date Ins ection Summar Areas Ins ected:
Routine, announced inspection by resident and Region-based inspectors of control room operations, licensee action on previous inspection findings, operational safety verification, surveillance program, maintenance program, licensee event reports, special inspection topics, and procedural adherence.
Results:
~0erations
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Operators responded well to the reactor scram of April 5, 1995.
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The inspector identified a mispositioned switch that was caution tagged which indicated a lack of control over tagging activities.
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The inspector identified two instances in which operators made improper entries into the limiting condition for operation (LCO) log.
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The inspectors observed that, "during the plant shutdown of April 21 and 22, 1995, communications, formality, supervisory oversight, and log keeping did not meet management's expectations.
9505260050 950522 PDR ADOCK 05000397
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Operators did not always appropriately maintain the log of the plant cooldown during the plant shutdown of April 21-22, 1995.
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Operators did not perform timely trending or evaluation of off-normal control room ventilation differential pressures.
Maintenance Surveillances observed were performed properly and in accordance with procedures.
Maintenance observed was performed and documented properly.
En ineerin
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A system engineer exhibited good attention to detail in identifying a
nonconforming diesel generator breaker configuration.
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Engineers did not perform a
CFR 50.59 evaluation for the implementation of a minor modification associated with the replacement of a fire damper.
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Equipment qualification engineers applied incorrect factors to extend the qualified life of the containment atmosphere monitoring hydrogen and oxygen sensors, which resulted in plant operation with sensors that were beyond their qualified life.
Failures of the containment atmosphere monitoring hydrogen and oxygen sensor were not effectively trended.
Plant Su ort
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Some contractors were observed to be wearing dosimetry incorrectly.
Contractors also inappropriately propped open a fire door.
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Licensee craftsmen did not exhibit good contamination controls while working on a portable ventilation unit, which resulted in charcoal spread inside and outside the contaminated area boundary.
Summar of Ins ection Findin s:
Violation 397/9509-01 (Section 4.3)
was opened.
Violation 397/9345-08 (Section 8. 1) was reviewed and closed.
Followup Item 397/9429-01 (Section 9. 1) was reviewed and closed.
A noncited violation (Section 9. 1) was identified.
Attachments:
Attachment 1 - Persons Contacted and Exit Meeting Attachment
DETAILS
PLANT STATUS At the beginning of the inspection period, the plant was at 100 percent power.
On March 11, 1995, at 10: 16 a.m.,
operators reduced reactor power to 70 percent to change the control rod pattern and assess the impact of a small condenser tube leak.
Operators restored power to 100 percent at 7:09 p.m.
on March 11, 1995.
On April 5, 1995, at 9:57 a.m.,
the reactor automatically shut down on a turbine trip-reactor trip.
Operators restarted the reactor on April 10, 1995.
The reactor reached 100 percent power on April 14, 1995, at 9:54 p.m.
On April 21, 1995, operators began a reactor shutdown for the annual Refueling Outage R10.
The reactor was fully shut down on April 22, 1995, at 5:38 p.m.
Refueling Outage R10, scheduled for 42 days, was in progress at the end of the inspection period.
ONSITE FOLLOWUP TO EVENTS (93702)
2. 1 Reactor Scram on Hi h Reactor Vessel Level Turbine Tri On April 5, 1995, at 9:57 a.m.,
the plant experienced an automatic reactor scram resulting from a turbine trip caused by a malfunction in the high reactor vessel level turbine trip circuitry, which is separate from the reactor protection system.
The trip and scram occurred while instrument and control technicians were performing a surveillance on Channel B of the circuitry.
The circuitry, in order to protect the main turbine from high water level in the reactor vessel, requires a two-out-of-three logic to trip the main turbine and both reactor feed pumps.
Following the turbine trip and reactor scram, 4 of the 18 safety relief valves lifted at their set pressures to control reactor pressure.
All reactor protection systems appear to have functioned properly.
No other engineering safety features actuated during the event.
Immediately following the reactor scram, the inspector observed control room personnel to be orderly and focused in their response to the scram.
The control room supervisor appeared to communicate well with the control room staff, and necessary activities were accomplished to bring the plant to a stable condition.
When the turbine tripped, only Reactor Feed Pump A tripped, which indicated a
fault in Channel A of the trip circuitry.
Subsequent licensee investigation traced the problem to a faulty Agastat relay in Channel A.
The licensee noted that the failed relay, which was installed in October 1991, was continuously energized and near the end of its 4-year life.
During the previous refueling outage, the licensee had replaced similar Agastat relays in safety circuits, but had chosen to omit the relays associated with the high level reactor trip because they were nonsafety.
Before restarting, the licensee replaced additional nonsafety Agastat relays whose failure could result in plant challenges.
E
Associated with the event, Reactor Recirculation Pump, B tripped when shifting from 60 hz to 15 power.
The licensee later found that, during installation of one of the design change packages to add wiring for the adjustable speed drive modification, someone had apparently inadvertently opened the 15 hz excitation power switch.
The open circuit prevented Reactor Recirculation Pump B from shifting to 15 hz following the reactor scram.
During the event, the licensee declared main steam leakage control inboard excess flow control Check Valve EFC-V-18C inoperable because it indicated closed and was required to be open.
The licensee later determined that the valve was actually open and that there was a problem with the valve's position indication, The licensee repaired the valve's position indication prior to reactor restart.
On plant walkdowns following the event, the licensee found a failed vertical strut on the 24-inch nonsafety outlet piping from feedwater Heater 6B.
The strut had failed at its structural attachment due to high tensile loads.
The licensee's engineering group determined that the high loads were most likely due to thermal stratification which occurred while the plant was in hot shutdown.
The licensee performed nondestructive examinations of the adjacent affected feedwater heater nozzle and critical piping.
Results of the nondestructive examinations established that the affected feedwater nozzle and adjacent piping had not been damaged.
Using a different hanger configuration, engineering reanalyzed the piping stresses in this segment of the feedwater system.
Based on this analysis, the licensee removed the failed vertical strut and readjusted the adjacent spring support.
At the time of restart, engineering had not replicated the thermal stratification conditions in the piping analysis model to confirm the cause of the vertical strut failure.
However, engineering did communicate to operations the importance of minimizing time in the hot standby condition during subsequent shutdowns to mitigate the potential for thermal stratification conditions.
The inspectors will continue to monitor licensee actions related to this matter during future inspections, including any licensee actions related to the operational impact of minimizing time in hot standby.
PLANT OPERATIONS (71707, 92901)
3. 1 Plant Tours The inspectors toured the following plant areas:
Reactor Building Primary Containment Control Room Diesel Generator Building Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter
3.2 Ins ector Observations 3.2. 1 Sustained Observation of Reactor Shutdown On April 21 and 22, 1995, the inspectors observed the planned reactor shutdown prior to the commencement of Refueling Outage R10.
These observations consisted of control panel walkdowns, interviews with the various operators, and procedure reviews.
The inspectors concluded that the reactor was shut down safely, in accordance with licensee procedures.
The inspectors made the following observations during this inspection:
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Radio communications were good and included repeat backs and good transfer of data.
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A control room operator performed a thorough walkdown of the panels and found that there was an increasing trend in main lube oil temperature.
Investigation revealed that an automatic control valve had failed.
An equipment operator took manual control of the system and the temperatures returned to normal.
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Operators were inconsistent in pulling out the annunciator response procedures upon receipt of an annunciator.
The inspector observed the receipt of the annunciator for "MOISTURE SEPARATOR A REHEATER HIGH LEVEL" on April 22, 1995.
The operator acknowledged the annunciator, but did not refer to the annunciator response procedure.
The operator apparently assumed that this alarm had been received frequently during the shutdown sequence and was already being addressed.
The inspector noted that this was the first receipt of this annunciator during the shutdown.
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Communications within the control room crew were inconsistent.
The inspectors observed a number of occasions in which annunciators were received but the annunciator was not announced to the crew, and/or there was no repeat back by the control room supervisor or lead control room operator.
For example, at 6:26 p.m.
on April 21, an alarm for leak detection in the turbine building annunciated in the control room.
The control room operator acknowledged the alarm but did not announce the alarm.
The operator followed the annunciator response procedure and dispatched an equipment operator to the turbine building.
The lead reactor operator, who was unaware of the alarm, did not log receipt of the annunciator.
The equipment operator found a steam leak.
The annunciator cleared at 11:05 p.m.
and the lead reactor operator for the oncoming crew logged the clearance of the annunciator.
He then added a late entry that the annunciator was initially received at 6:30 p.m.
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The lead control room operator did not log a number of annunciators or significant equipment stops and starts.
In addition, a number of open ended entries were made in the control room operators lo ~
Command and control by the shift managers and control room supervisors was inconsistent.
The shift managers spent a large portion of their time in the shift manager's office addressing outage preparation rather than observing the performance of the crews.
The control room supervisor was similarly distracted from placing his full attention towards the plant shutdown.
Along with the above issues, the maintaining management oversight the above issues were observed'ollowing performance evaluation inspectors noted that the licensee was in the control room.
Despite this oversight, In addition, the licensee initiated the requests (PERs):
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PER 295-0370:
Operators failed to take the cooldown watch readings at 15-minute intervals per Plant Procedure Manual (PPH) 7.4.4.6. 1.
This was caused by an inadequate shift turnover with respect to these logs.
The Technical Specification (TS) cooldown rate was not exceeded.
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PER 295-0373:
Operators had difficulty in swapping residual heat removal (RHR)
pumps from RHR 8 to A.
Operators took 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 37 minutes to switch loops due to procedure problems.
The TS allow shutdown cooling to be secured for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The inspectors discussed these observations with the plant manager.
The plant manager stated that, to improve operator performance, additional 24-hour control room oversight by experienced managers had been established to observe crew performance.
The licensee issued a charter for the oversight individuals to ensure that management's expectations would be implemented during all normal and abnormal operation.
The plant manager also stated that the licensee would continue to pursue improvements in the day-to-day performance of the control room operators.
3.2.2 Operating Logs and Records The inspectors reviewed operating logs and records against TS and administrative control procedure requirements.
On March 21, 1995, during review of the Technical Specification/Limiting Condition for Operation/Inoperable Equipment Log, the inspector noted discrepancies.
The inspector noted that the licensee had two entries for Intermediate Range Monitors (IRMs)
G and H, but did not correctly reflect the requirements in the TS.
The senior reactor operator wrote in the "Action" section for the log entries,
" IRHs are not required in Node 1."
The inspector noted that TS 3.3.7.5 requires two IRHs per channel to be operable for accident monitoring; therefore, the senior reactor operator's entries in the LCO log were incorrect.
The inspector also noted that three of the LCO log forms had not been verified prior to use, as expected by the licensee.
The inspector notified the shift manager, who initiated PER 295-0233 to document this issue and to propose corrective action The inspector further reviewed plant status and noted that the licensee did have at least the required number of IRMs to meet TS requirements.
Therefore, the inspector concluded that this observation was of low safety significance.
However, the inspector noted that several recent NRC inspection reports have indicated deficiencies in licensed operator knowledge of the TS.
The licensee was in the process of implementing corrective actions for these previous knowledge-based errors.
The licensee stated that they would continue to monitor operator knowledge and application of the TS and that their long-term initiatives should improve this area.
3.2.3 Monitoring Instrumentation The inspectors observed process instruments for correlation between channels and for conformance with TS requirements, and no discrepancies were identified.
3.2.4 Shift Manning The inspectors observed control room and shift manning for conformance with
CFR 50.54(k),
TS, and administrative procedures.
The inspectors also observed the attentiveness of the operators in the execution of their duties.
The inspectors concluded that shift manning was in conformance with the applicable requirements and operators were generally attentive to duties.
The control room was observed to be free of distractions such as nonwork-related radios and reading materials.
3.2.5 Equipment Lineups The inspectors verified that valves and electrical breakers were in the position or condition required by TS and administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Appropriate entry into TS limiting conditions for operation were verified by direct observation.
3.2.6 Equipment Tagging The inspectors observed selected equipment, for which tagging requests had been initiated, to verify that tags were in place and the equipment was in the condition specified.
One problem was noted during these observations as discussed below.
3.2.6.
Repositioned Caution Tagged Switch On March 14, 1995, during a tagout walkdown, the inspector noted that a
component in the control room was not in the position specified by the clearance order.
A caution tag required an IRM control switch to be in the
"bypass" position, but the inspector found the switch in the "test" position.
The inspector notified the shift manager, who researched the apparent discrepancy.
The shift manager noted that m'aintenance personnel had'performed troubleshooting of the IRM in accordance with a work order.
The maintenance
personnel repositioned the switch following the troubleshooting because they had found that the instrument exhibited less erratic behavior in the "test" rather than the "bypass" position.
The shift manager stated that the technicians should have notified operations to change the designation of the caution tag following the troubleshooting, to ensure that the tag accurately reflected system status.
The shift manager cleared the tag and reissued the clearance order with the new switch position specified.
The inspector concluded that this occurrence was of low safety significance.
However, the inspector noted that this observation emphasized the need to ensure that clearance orders accurately reflect the desired conditions, including caution tags.
The inspector discussed this issue with the plant manager, who acknowledged the inspector's comments.
3.2.7 General Plant Equipment Conditions The inspectors observed plant equipment for indications of system leakage, improper lubrication, or other conditions that would prevent the system from fulfillingits functional requirements.
Annunciators were observed to ascertain their status and operability.
No problems affecting system function were identified.
3.3 En ineered Safet Features Walkdown The inspectors walked down selected engineered safety features (and systems important to safety) to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
Proper lubrication and cooling of major components were also observed for adequacy.
The inspectors also verified that certain system valves were in the required position by both local and remote position indication, as applicable.
The inspectors walked down selected portions of the following systems on the indicated dates:
~Sstem, Diesel Generator Systems, Divisions 1, 2,
and
Low Pressure Coolant Injection Trains A, B, and C
Low Pressure Core Spray High Pressure Cor'e Spray Reactor Core Isolation Cooling Dates March
March 17, 27, April 16 March 17, April 16 March 17, April 16 March 17, April 16
-10-RHR Trains A and B
Standby Gas Treatment Standby Liquid Control 125V DC Electrical Distribution, Divisions
and
250V DC Electrical Distribution March 17, April 16 March
March
March 27, April 18 March 27, April 18 The inspectors concluded that engineered safety features systems were in good material condition and were aligned in accordance with the applicable licensee procedures for the portions walked down.
ONSITE ENGINEERING (37551, 92903)
The inspectors performed inspections of the following onsite engineering related activities during this inspection period:
4. 1 Hi h Pressure Core S ra HPCS Diesel Generator DG Breaker Controls On March 21, 1995, a licensee engineer identified that the HPCS DG-3 breaker controls did not have a generator voltage buildup logic permissive for DG-3 breaker closure.
This is contrary to descriptions of the DGs in the Final Safety Analysis Report (FSAR).
The licensee initiated PER 295-0231 to evaluate the safety significance, determine operability, and determine appropriate corrective actions.
The licensee noted that a generator voltage buildup interlock in the DG output breaker control logic is one logic permissive that is part of the standard industry control system design.
This assures that sufficient conditions are met for the DG breaker to close to establish a ready-to-load condition on the safety bus.
This permissive is relied upon for a successful start of the HPCS pump motor.
DG-1 and DG-2, the diesels supporting Division 1 and 2 of safety equipment, have this feature.
The licensee performed an operability assessment and noted that if DG-3 connects to the bus without adequate voltage buildup, there would not be damage to any of the components in Division 3.
In addition, the licensee noted that all previous surveillance tests on DG-3 had indicated that voltage buildup on DG-3 was sufficient such that the lack of the breaker permissive would not affect operation of the machine.
The inspector interviewed the individuals, evaluated the operability assessment, the FSAR, and previous surveillance tests and determined that the licensee's assessment of the event was satisfactory.
The inspector discussed this issue with the electrical engineering supervisor, who stated that the decision of whether to change the breaker to conform with the FSAR or change the FSAR will be made in the near futur.2 Fire Dam er WMA-FD-7 Re lacement On March 22, 1995, a licensed operator, who was reviewing required reading, noted that control room to cable spreading room differential pressure was lower than that allowed by a
new procedure.
As a result, the licensee initiated PER 295-0238.
The PER documented the inoperability of WMA-FN-54B due to the fan not being able to maintain control room differential pressure greater than or equal to a positive 0. 175 inch water gauge (w.g.).
The inspectors conducted followup inspection of this event to assess the effectiveness of the corrective actions of previous control room ventilation system events.
The inspectors reviewed the incident review board (IRB)
report, the PER, and discussed the event with members of licensee management.
The inspectors also discussed control room ventilation system operation with selected plant operators.
The licensee's IRB found that Work Order Task NF70, which replaced Fire Damper WMA-FD-7, was released for work on February 22, 1995.
On February 24, 1995, in order to access Fire Damper WMA-FD-7, craftsmen removed a section of ventilation ducting that served as the suction for Cable Spreading Room Fan WMA-FN-52B.
Removal of this ducting resulted in the cable spreading room pressure increasing.
Because cable spreading room pressure increased, the differential pressure between the control room and the cable spreading room decreased.
TS require that the control room pressure be positive 0. 125 inches w.g.
above the cable spreading room pressure.
PPM 7.4.7.2. 11, "Control Room Envelope Pressurization Test," requires a positive 0. 175 inches w.g., which takes into account instrument accuracy and calibration accuracy.
The licensee's IRB concluded the following:
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Between March 8-10, 1995, and March 20-22, 1995, WMA-FN-54B could not achieve the required TS pressurization value.
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The
CFR 50.59 review for this work did not include evaluating the impact to plant operations during the installation of the modification.
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The field engineer was not aware of the requirement for a barrier permit.
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The corrective actions for previous problems with the control room ventilation system did not include the potential impact of work on adjoining ventilation systems.
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Operators missed opportunities for more timely identification.
The IRB recommended the following corrective actions:
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project management set performance standards consistent with management expectations;
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the event be reviewed by operations, engineering, and work planning personnel; and
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training analyze the event, as well as related events from last fall, to address knowledge deficiencies concerning control room ventilation and related structures.
In dispositioning PER 295-0238, the licensee determined the event had three causes:
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Engineers had not adhered to PPM 1.4. 1 that required a
CFR 50.59 review for the implementation of plant modifications.
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PPM 1.3.5.7,
"Barrier Impairments," did not consider how work affecting the ventilation systems of areas adjacent to the control room could affect the ability to pressurize the control room.
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The production scheduling shift manager missed the effect of the work during his review of the impact statement.
The licensee implemented the following corrective actions:
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revise PPM 1.4. 1, "Plant Modifications," to include only a comprehensive
CFR 50.59 review, and
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revise PPM 1.3.57, "Barrier Impairments," to include considerations of the cable spreading room and their associated air handling units and ductork.
The licensee concluded that the safety significance of this event was minimal because the control room could have always been pressurized and that only Train B of control room emergency filtration would not have achieved the TS requirement for two separate 3-day periods, which was within the allowed outage time of TS.
Based on the inspectors'eview of the IRB and PER, and discussions with a limited number of licensed operators, the inspector concluded the following:
Corrective actions that the licensee initiated to assure that
CFR 50.59 evaluations would be performed for the implementation of modifications were not fully effective.
Corrective actions that the licensee had implemented to assure that operators had an adequate knowledge level to operate and maintain the control room ventilation system were not fully effective.
Corrective actions that the licensee had taken to assure the work review process would identify the potential impact of low priority work on plant operations were not fully effectiv When presenting these conclusions to licensee management, the inspector learned that the licensee had recently implemented a review of significant PERs by senior managers and that these managers had concluded that PER 295-0238 required revision.
Management's concerns with the PER included the conclusions that the inspectors developed during the inspection of this issue.
The licensee also discussed this event during an enforcement conference conducted on April 7, 1995, and indicated that this event had caused them to reflect on the three previous control room ventilation issues and the corrective actions that had been taken.
The licensee indicated that the previous corrective actions had not effectively prevented recurrence of control room ventilation events.
Therefore, they planned to implement the following additional actions:
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Evaluate the training operators received on the control room ventilation system.
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Eliminate implementation only (retrofitted) of 10 CFR 50.59 reviews and require only one safety assessment, that assessment to include an evaluation of design and implementation of the change.
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Perform a review of the entire work process to identify and correct weaknesses in the work process.
The inspector concluded that the additional corrective actions which the licensee implemented should prevent recurrence of problems with the operation and maintenance of the control room ventilation system.
The need for additional NRC action related to this event will be evaluated along with actions associated with the April 7, 1995, enforcement conference, 4.3 Containment Monitorin S stem CMS H dro en and Ox en Sensors On March 28, 1995, the licensee initiated PER 295-0251 to document a concern with the qualified life of the CMS hydrogen and oxygen sensors.
The PER stated that the qualified life of the sensors must be reduced to 18 months based on information received from the vendor.
The vendor notified the licensee that the qualified life should be reduced from 6 years to 18 months because the influent gas temperature was 132'F as opposed to 110'F.
The elevated influent gas temperature cause's accelerated evaporation of sensor electrolyte, resulting in accelerated loss of sensitivity and sensor failure.
The PER noted that one of the two installed hydrogen and both oxygen sensors had been in service for more than 18 months.
The licensee performed a followup assessment of operability (FAO) and concluded that the three sensors which had been installed for greater than 18 months (78, 60, and 43 months)
were operable.
The licensee concluded that the sensors were operable based on the vendor's review of the sensors'arch 8,
1995, calibration and the expected reduced evaporation rates following a loss of coolant accident due to the higher relative humidity of the influent process strea The inspector conducted followup inspection of this issue to assess the thoroughness of the licensee's FAO.
The inspector discussed this issue with the plant manager, the system engineer, the equipment qualification engineer, and the equipment qualification manager.
The inspector also reviewed the licensee's qualification documentation for these sensors.
The inspector had the following observations after reviewing the FAO:
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The vendor recommended an 18-month qualification based on a 132'F process stream effluent temperature resulting in increased electrolyte evaporation; however, some of the licensee's sensors had remained operable for substantially greater than 18 months (some in excess of the qualified life of 6 years)
with the higher process stream temperatures.
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The licensee's conclusion of operability was based on the ability to predict failure from a review of calibration data and the theory that increased moisture in the process influent stream during, an accident would reduce the evaporation rate of the electrolyte.
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The licensee's FAO did not include a detailed examination that included a
review of past WNP-2 operating history of the hydrogen and oxygen sensors.
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The assessment did not show that subsequent failure of the equipment would not provide misleading information to the operator.
The inspector shared these observations with licensee management.
On April 3, 1995, the licensee revised the FAO and included sensor sensitivity graphs, a sensor cell diagram, sensor response to a loss of coolant accident diagram, and documented telephone conversations the licensee had with the vendor.
The licensee again concluded that the sensors installed for greater than 18 months would continue to function properly up to Refueling Outage R10 which was scheduled to begin on April 22, 1995.
The licensee concluded operability based on the following:
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From current calibration data, the cell sensitivity of these sensors was not trending to indicate that the cell was deteriorating due to electrolyte evaporation.
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Testing showed that, if a sensor was properly functioning at the start of a loss of coolant accident, the sensor would function during the accident, and electrolyte level would not fall significantly.
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The electrolyte level should not diminish significantly due to increased relative humidity during the loss of coolant accident.
The inspector noted that the revised FAO was more thorough and complete than the initial FAO, providing a better technical justification to assess and determine operability.
In reviewing the FAO and vendor. manual information, the inspector had the following concerns with the revised FAO:
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It appeared that future detector operability, including operability through an accident, could not be determined based on the available test data and detector sensitivity for a sensor that had exceeded its qualified life.
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It appeared that insufficient test data was available to assess electrolyte level evaporation during thermal aging and qualification testing; therefore, the conclusion that, if a sensor was properly functioning at the beginning of an accident, it would function properly during an accident was suspect.
The inspector also noted that the licensee had improperly extended the operability of the sensors to 125 percent beyond their initial qualified life of 6 years.
This resulted in the plant operating with sensors beyond their qualified life.
The inspector found that the hydrogen and oxygen sensors at WNP-2 had a high failure rate with failure times of less than the 6 years.
The inspector discussed these issues with licensee management and engineers.
The licensee agreed that WNP-2 had operated at least two of the sensors beyond their qualified life.
The licensee indicated that this occurred because of equipment qualification engineers assuming that the sensor qualification was based on thermal aging and not operating experience.
As corrective actions, the licensee plans to change the qualified life of the hydrogen and oxygen sensors to less than 6 years based on vendor information and failure history.
In addition, other equipment that was qualified by thermal aging will be reviewed to ensure that the qualified life is properly characterized.
The inappropriate extension of the qualified life of hydrogen and oxygen sensors was identified as a violation of licensee standard EgES-2,
"Technical Requirements for Electrical Equipment Environmental gualification" (Violation 397/9509-01).
With respect to the hydrogen and oxygen sensor operating history, the inspector found that, since 1986, when the licensee first installed these sensors, there have been six sensor failures due to low electrolyte level.
The installation times at failure were as long as 4 years and as short as 1 year.
This represents a high failure rate of the detector and suggests that the 6-year qualified life for the detectors is too long.
Additionally, this suggests that the licensee trending program requires strengthening to assess components that are qualified by operating history.
As corrective action, the licensee plans to reduce the qualified life of the sensor and review other components that had been qualified by operating experience.
On April 9, 1995, following a reactor scram, the licensee replaced the two oldest installed sensors, thereby eliminating the inspector's concerns with the sensor which had exceeded its 6-year qualified life.
The licensee plans to change the preheat temperature of the influent gas during the current Refueling Outage R1 In summary, the inspector concluded:
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The licensee had inappropriately extended the qualified life of CMS hydrogen and/or oxygen sensors.
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The FAO did not appear to provide a sound engineering basis for the operability of the sensor that had exceeded its qualified life.
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The licensee's program for trending and evaluating equipment failures requires strengthening.
~'icensee action to replace the oldest installed sensors was viewed as appropriate.
PLANT SUPPORT ACTIVITIES (71750)
The inspectors evaluated plant support activities based on observation of work activities, review of records, and facility tours.
The inspectors noted the following during this evaluation.
5. 1 Fire Protection The inspectors observed firefighting equipment and controls for conformance with administrative procedures.
Due to concerns with Thermo-Lag and fire seals, and because a number of fire doors were propped open to support work, the inspectors noted that a high number of fire impairments existed for which fire tours were being conducted.
5. 1.1 Propped Open Fire Door On April 14, 1995, the inspector found Door R105 propped open.
Door R105 is a
watertight door for flooding protection and is a fire door which is at the entry into the reactor core isolation cooling pump room.
A fire impairment had not been issued for the door to be open and, therefore, was not added to the hourly fire tour.
The inspector noted that no personnel were in the area, but a large amount of tools, scaffolding, and other material was apparently staged for the upcoming outage.
The inspector notified the shift manager, who initiated PER 295-0333 to document this issue and propose corrective actions.
The licensee's investigation into this issue revealed that the likely cause was contractors arriving on site recently that were not familiar with WNP-2 fire and flooding protection programs.
The inspecto}
discussed this issue with the plant manager.
The inspector concluded that the licensee did not appear to closely monitor contractor performance to ensure conformance with all WNP-2 programs and procedures.
5.2 Radiation Protection Controls The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance
-17-with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with radiation work permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
5.2. 1 Dosimetry Placement On a number of occasions during this inspection period, the inspectors noted a
number of individuals wearing their dosimetry improperly.
Some individuals wore their alarming dosimeters with the detector element facing towards themselves rather than away.
The inspectors also observed other individuals not wearing their alarming dosimeter and thermoluminescent dosimeter together.
The inspectors discussed this issue with the radiation protection manager.
The licensee held a timeout on health physics issues at the end of the inspection period.
5.3 Plant Housekee in The inspectors observed plant conditions and material/equipment storage to determine the general state of cleanliness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination, Housekeeping was observed to be generally good during the inspection period.
5.4
~Securit The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that the search equipment at the access control points was operational, that the vital area portals were kept locked and alarmed, that personnel allowed access to the protected area were badged and monitored, and that the monitoring equipment was functional.
No problems were noted during these observations.
5.5 Emer enc Plannin The inspectors toured the emergency operations facility, the Operations Support Center, and the Technical Support Center and ensured that these emergency facilities were in a state of readiness, Housekeeping was noted to be very good and all necessary equipment appeared to be functional.
The inspectors reviewed chemical analyses and trend results for conformance with TS and administrative control procedures.
Plant chemistry was satisfactory during this inspection perio.7 Conclusions Plant support performance was generally good during this inspection period.
However, licensee management did not correct previous concerns with dosimetry placement which recurred during this inspection period.
In addition, the inspector concluded that finding a fire and flooding door open appeared to indicate that control of contractors on site required strengthening.
SURVEILLANCE TESTING (61726)
The inspectors reviewed surveillance tests required to be performed by the TS on a sampling basis to verify that:
(1)
a technically adequate procedure existed for performance of the surveil-lance tests; (2)
the surveillance tests had been performed at the frequency specified in the TS and in accordance with the TS surveillance requirements; and (3)
test results satisfied acceptance criteria or were properly dispositioned.
The inspectors observed portions of the following surveillance tests on the dates shown:
Procedure 7.4.8.1.1.2.11 16.6.2 Descri tion DG-2 Monthly Operability Test Plant Service Water Radiation Monitor Calibration Dates Performed Harch
March
7.4.3.2.1.22A.
7.4.3.1.1.49 Main Steam Line High Flow Channel A Channel Function Test/Channel Check Average Power Range Monitor and Core Thermal Power Channel Calibration March 29 April 21 7.4.6.4.1.2 Containment Vacuum Breaker Operability Checks April 21 The inspectors concluded that these surveillances were performed and documented properl MAINTENANCE OBSERVATIONS (62703)
During this period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required quality assurance/quality control involvement, proper use of clearance tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors witnessed portions of the following maintenance activities:
Descri tion TG-9602 Repair and Replace Rod Position Indication System Card for Control Rod 22-03 Dates Performed March
Repair CRD-SV-112/5415, Replace 0.5 Inch Solenoid Withdraw Valve Troubleshoot OG-AG-60 April 4 April 14 The inspectors determined that these maintenance activities were performed and documented properly.
With respect to corrective Naintenance Task CRD-SV-122/5415 to replace the 0.5-inch solenoid withdraw valve, the inspector had the following observations.
The subject control rod drive (CRD) solenoid valve was replaced by the licensee because of problems with the CRD withdrawal function (skipping a notch during notch-by-notch withdrawal).
The responsible maintenance supervisor was present during the task.
Replacement and maintenance activities were performed in accordance with procedures.
A health physics technician was present and was observed to admonish the maintenance technicians performing the tasks when they appeared to be deviating from less than ideal as-low-as-reasonably-achievable (ALARA) practices.
The maintenance technicians appeared to take ownership of the procedures when they identified and subsequently enacted steps to enhance the quality of the task procedure by recommending that steps be added to the procedure to clarify required valve and gasket orientation.
During removal of the solenoid valve, potentially radioactive water from the CRD system sprayed the health physics technician, quality control technician, and NRC inspector.
Before proceeding, the technicians and inspector were verified not to be radioactively contaminated.
The licensee was investigating ways to better control the potential for spray from future work activities on this system.
By the time the inspection period closed, licensee maintenance technicians had devised a special shield for future work activitie ~ I
-20-
FOLLOWUP (92901, 92902, 92903, 92904)
8. 1 Closed Violation 397 9345-08
"Failure to Enter the A
licable TS Action Statement" This violation involved the failure of the licensee to enter the applicable TS action statement when performing surveillance testing on the containment hydrogen and oxygen monitors, an activity during which they were inoperable'ubsequent investigation by the licensee as to the cause of this event revealed that guidance on declaring equipment inoperable while performing tests had been provided as early as 1991 in NRC Generic Letter 91-18.
The licensee's operational events review failed to recognize the significance at the time.
The requirement for declaring equipment inoperable and entering the applicable TS action statement (when testing required removal from service)
was not incorporated until identified in 1993 during the TS Surveillance Improvement Project.
In 1993, paragraph 8.5.2 of PPM 1.5. 1, "Technical Specification Surveillance Testing Program,"
was revised to include these requirements.
This significant change to operating procedures was not emphasized to the operating crews, because neither procedure reviewers nor the Plant Operating Committee (POC) recognized its significance at the time of their review.
Licensee corrective actions to resolve the problem and to prevent recurrence included the following:
~
Operations personnel and other appropriate personnel were provided with guidance and training to ensure compliance with paragraph 8.5.2 of PPM 1.5.1.
~
A POC procedure review subcommittee was established as part of the procedure change management process to perform an additional procedure review prior to general POC review.
~
The original operational events review which reviewed NRC General Letter 91-18 was reopened to ensure that pertinent points were adequately addressed.
As a consequence, two other procedures were revised to incorporate Generic Letter 91-18 guidance.
The inspector considered the corrective actions to be appropriate to the circumstances and verified that they had been accomplished.
MAINTENANCE FOLLOWUP (92902)
9. 1 Closed Followu Item 397 9429-01
"Measurin and Test E ui ment METE Deficiencies not Documented Per Procedures" In September of 1994, licensee quality assurance personnel identified that, from the period of April 18, 1994, to September 6,
1994, approximately 70 out of tolerance METE deficiency reports had not been documented as required by licensee procedures.
PPM 1.5.4,
"Control of Measuring and Test Equipment,"
-21-Paragraph 6.9, requires M&TE deficiency reports to be issued if M&TE fails any calibration tests and the equipment has been used in the field.
In addition, PPM 1.5.4 requires that if an M&TE deficiency report cannot be appropriately dispositioned, a
PER shall be written'ubsequent licensee review revealed an additional 60 instances of failure to follow procedures.
The NRC performed a followup investigation of the licensee's response to this event.
The inspector noted that this event had minor safety significance and posed no issues in which operability of safety systems was in question.
In addition, the NRC noted that the licensee had taken disciplinary action against the individual, who resigned.
The licensee's corrective actions-appeared to be thorough and to have addressed the root causes.
The NRC investigation also concluded that the individual willfullyviolated approved licensee procedures.
However, these violations appeared to be the isolated actions of a low level individual within the licensee's organization.
Therefore, because these violations appear to meet the criteria for the exercise of discretion of Section VII.B(2) of the enforcement policy, this violation is not being cited.
The inspector reviewed the licensee's corrective action packages for this event and verified that the licensee's actions were complete,
ATTACHMENT 1
PERSONS CONTACTED Washin ton Public Power Su
S stem
- V. Parrish, Vice President Nuclear Operations
- J. Burn, Engineer'ing Director G. Smith, guality Assurance Director P.
Bemis, Regulatory and Industry Affairs Director
- J. Baker, Training Director
- R. Webring, Support Services Director
- J. Swailes, Plant General Manager H.
Reddemann, Technical Services Division Manager
- C. Schwarz, Operations Manager
- T. Love, Chemistry Manager R. Barbee, System Engineering Manager J. Albers, Radiation Protection Manager
- D. Swank, Licensing Manager
- J. Huth, Plant Assessments Manager
- W. Sawyer, Operations Support Manager
- T. Heade, Technical Programs Manager
- G. Sanford, Planning, Scheduling, Outage Manager
- V~ Shockley, Assistant to Radiation Protection Manager H. Nolan, Radwaste Supervisor N. 2immerman, BOP Technical Services Supervisor
- H. Honopoli, Maintenance Manager
- W. Barley, Corporate Radiation Health Officer R. Utter, Emergency Planner A. Barber, Senior guality Assurance Engineer M. Hedges, Corporate Chemist J.
Pedro, Licensing Engineer
- B. Hugo, Compliance Engineer Bonneville Power Administration
- D. Williams, Nuclear Engineer U.S. Nuclear Re ulator Commission
- A. Beach, Director, Division of Reactor Projects
- D. Chamberlain, Acting Chief, Project Branch E
- R. Barr, Senior Resident Inspector
- D. Proulx, Resident Inspector The inspectors also interviewed various control room operators, shift supervisors, shift managers, and maintenance, engineering, quality assurance, and management personnel.
- Attended the exit meeting on Hay 1, 199 EXIT MEETING An exit meeting was conducted on May 1, 1995.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee acknowledged the inspectors'indings.
The licensee did not identify as proprietary any of the information provided to, or reviewed by, the inspector e I
ATTACHMENT 2 ACRONYMS ALARA CMS CRD DG FAO FSAR HPCS IRB IRM LCO METE NRC PER POC ppM RHR TS W.g.
WNP-2 as-low-as-reasonably-achievable containment monitoring system control rod drive diesel generator followup assessment of operability Final Safety Analysis Report high pressure core spray Incident Review Board intermediate range monitor limiting condition for operation measuring and test equipment U.S. Nuclear Regulatory Commission problem evaluation request Plant Operating Committee plant procedures manual
.
residual heat removal Technical Specifications water gauge Washington Nuclear Power Supply System, Unit 2
a