IR 05000397/1995015
| ML17291A899 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 07/05/1995 |
| From: | Chamberlan D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17291A897 | List: |
| References | |
| 50-397-95-15, NUDOCS 9507120048 | |
| Download: ML17291A899 (44) | |
Text
ENCLOSURE
U.S.'UCLEAR REGULATORY COMMISSION REGION I V NRC Inspection Report:
50-397/95-15 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:
April 23 through June 3,
1995 Inspectors:
R.
CD Barr, Senior Resident Inspector D. L. Proulx, Resident Inspector D.
E. Corporandy, Project Inspector G.
E. Werner, Reactor Inspector Approved 7 S/qS-
.
C am er ain, Acting C ie
, ProJects rane E
ate 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 (LERs),
and special inspection topics.
Results:
~0erati ons The fire brigade did not secure the area when smoke was noted in the high pressure core spray diesel generator (DG) room.
A potential for personnel injury existed in the event of reflash (Section 2.2.3).
The control room crew did not exhibit good command, control, and prioritization during response to the fire in the HPCS DG room (Section 2.2.3).
Nine errors were made during breaker lineups, indicating that self-checking still requires improvement.
The problem evaluation request (PER)
for this issue contained incorrect information concerning rechecking breaker positions.
The licensee responded to this issue (Section 3.2.5).
9507l20048 950705 PDR ADQCK 05000397
-2-
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Due to inadequate log keeping and procedures, operators failed to ensure that the SDC pump was secured for less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per 8-hour period and operators did not perform hourly monitoring of temperatures that were representative of reactor coolant temperature (Section 2.3. 1).
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Equipment operators improperly attached restraints for compressed gas cylinders (Section 3.3.2).
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Refueling was performed in a formal and controlled manner and no errors in the sequence were noted, which was a significant improvement over previous refuelings (Section 8).
Maintenance
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Surveillances observed were performed properly and in accordance with procedures (Section 6).
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Maintenance observed was performed and documented properly (Section 7).
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Personnel performing maintenance on Valve CRD-V-14B did not implement the fire protection program in that the firewatch failed to remain in the area for 30 minutes following hot work (Section 7).
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The licensee used an uncalibrated computer point to meet acceptance criteria in a diesel generator surveillance (Section 6. 1.4).
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The wetwell was opened for maintenance, but was not posted as a foreign material exclusion area (Section 3.2.7).
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A test port was left loose following surveillance testing of the standby gas treatment system (Section 3.3.3).
En ineerin Engineering personnel effectively resolved high vibration levels for Standby Service Water Pump SW-P-1B, although a more aggressive questioning of the effects of the difference in the weight of the motors may have avoided this problem prior to the motor's installation (Section 4. 1).
A fire in a diesel generator regulator resulted from a combination of inadequate static testing of the motor-operated potentiometer (MOP);
inadequate work order instruction; and poor coordination between the system engineer, the equipment operator; and the control room (Section 2.2.5).
Plant Su ort
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A spill during preparations for chemical decontamination resulted from less than adequate procedures and a lack of good communications (Section 2.1.1).
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Poor planning and control of work resulted in a barrel of highly radioactive filters overturning (Section 2.1.2).
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The licensee's exposure controls during Refueling Outage R10 resulted in a
total dose well under the projected dose (Section 5.2).
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On two occasions the licensee exhibited weak contamination controls in that two radiological catches were left overturned in clean areas (Section 5.2).
Summar of Ins ection Findin s:
Violation 397/9515-01 (Section 7)
was opened.
LER 397/93-28, Revision 0 (Section 11. 1),
was closed.
LER 397/93-30, Revision 2 (Section 11.2),
was closed.
LER 397/94-01, Revision 0 (Section 11.3),
was closed.
LER 397/94-06, Revision 0 (Section 11.4),
was closed.
LER 397/94-09, Revision 0 (Section 11.5),
was closed.
LER 397/94-13, Revisions 0,
1, and 2 (Section 11.6),
were closed.
LER 397/94-16, Revision 0 (Section 11.7),
was closed.
Violation 397/9345-09 (Section 10. 1)
was reviewed and closed.
Violation 397/9402-02 (Section 10.2)
was reviewed and closed.
Violation 397/9415-01 (Section 10.3)
was reviewed and closed.
Violation 397/9415-02 (Section 10.4)
was reviewed and closed.
Attachments:
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Attachment
Persons Contacted and Exit Heeting
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Attachment
DETAILS
PLANT STATUS At the beginning of the inspection period, the plant was in Mode 3 (Hot Shutdown) with plant cooldown for Refueling Outage R10 in progress.
The plant entered Mode 4 (Cold Shutdown)
at 7:32 a.m.
on April 23.
Following cooldown the licensee commenced drywell and reactor disassembly and entered Mode
(Refueling) at 4:25 a.m.
on April 25.
following completion of core alterations and other outage activities, the licensee reassembled the reactor and entered Mode 4 at 11:04 p.m.
on May 23.
The plant was in Mode 4 at the end of the inspection period.
ONSITE FOLLOWUP TO EVENTS (93702)
2. 1 Reactor Water Cleanu S stem RWCU Decontamination
~Back round During Refueling Outage R10, the licensee performed chemical decontamination of the RWCU system to reduce system, component, and piping radiation levels.
The chemical decontamination included the connection of a temporary filtering unit and hoses to flanged connections in the RWCU system.
Water and a chemical solution were circulated through the RWCU system and the decontamination unit where the particulate contamination was filtered from the solution.
The radioactive particulate material primarily consisted of metal oxides, some of which were radioactive.
The decontamination appeared to be particularly effective, resulting in more filter loading than the licensee had expected.
Therefore, the Filters were more radioactive than had been expected.
The licensee had planned to temporarily store the filters in a
valve gallery of the reactor building.
2. 1. 1 Spill During RWCU Chemical Decontamination On May 6, 1995, during preparations for chemical decontamination of the RWCU system, personnel noted that water was flowing into and out of a sleeve from a flanged joint in the RWCU system.
Approximately 10 gallons of contaminated primary coolant had spilled on the floor at the entrance to the drywell.
The licensee believed that the water was flowing through Valves RWCU-V-100 and RWCU-V-106, which had been opened to support the Fill of the system.
The licensee initiated PER 295-0483 and conducted an Incident Review Board ( IRB).
The inspector performed followup inspection of this issue.
2. 1. 1. 1 Procedure Reviews The inspector reviewed the RWCU chemical decontamination procedures.
The licensee used Plant Procedures Manual (PPH) 8.5. 11,
"Reactor Water Cleanup System Chemical Decontamination,"
Work Order Task (WOT) PP1202, and the vendor procedure to perform this operation.
These documents permitted concurrent activities.
The activities included connecting hoses between plant systems and the vendor's equipment and removing danger tags to allow filling and
venting of the decontamination equipment.
The instructions also permitted options to connect equipment at one of several locations.
2. 1. 1.2 Event Sequence PPN 8.5.11 required verification that all hoses were properly connected prior to performing the steps to fill and vent the decontamination equipment.
Before that verification had been completed, however, the project engineer requested that the control room remove the clearance tags from Valves RWCU-V-100 and RWCU-V-106.
These valves had been manually seated to prevent leakage past their seats.
Although the project engineer knew that opening these valves would result in the decontamination system being filled, he assumed that the vendor had already connected the hoses and aligned the system.
The system engineer did not verify his assumption with the vendor prior to proceeding, resulting in a contaminated water spill.
Additionally, water leaked from a flanged connection near Valve RWCU-V-100.
Step 4.2 of the WOT permitted the user to unbolt and remove one of two flanges located near Valves RWCU-V-100 and RWCU-V-106.
A mechanic loosened the bolts for one of the flanges with the intent to connect temporary decontamination hoses.
On the following day, a different mechanic connected the decontamination hoses to a different flange.
Due to a miscommunication, the flange nearest to Valve RWCU-V-100 was unknowingly left loose.
Also,'he mechanic who loosened the bolts failed to install a radiological collection reservoir (catch)
as directed by the radiation work permit when flange bolts were loosened.
These errors resulted in an uncontrolled contaminated water spill.
When operators removed the danger tags and unseated Valves RWCU-V-100 and RWCU-V-106, water filled the decontamination unit, flowed from a I/2-inch vent hose, and leaked from the loosened flange.
The licensee and the vendor isolated the leaks by shutting a valve on the decontamination unit.
When mechanics tightened the loosened flange bolts, they did not tighten the bolts per ASNE procedures, despite the flange being a part of the reactor coolant pressure boundary.
2. 1. 1.3 Licensee Investigation On Nay 6, 1995, the licensee initiated an IRB.
The IRB noted the sequence of events as described above.
In addition, the IRB identified that the vendor issued a revision to their vendor procedure without the licensee's knowledge or approval.
The revision replaced a normally closed air operated valve with a vent hose that had two open manual valves.
This change was not approved by the Plant Operations Committee, as required by the licensee's agreement with the vendor.
This vent hose was the location of one of the two spills.
The IRB noted that a senior line manager had been assigned to oversee the decontamination.
No prejob briefing of licensee or vendor personnel had occurred prior to this event.
The IRB noted that the senior line manager was primarily acting in a "production role" and not providing leadership to ensure
safe and conservative decision making.
The IRB concluded that communications, coordination, and teamwork among the project engineer, senior line manager, licensee mechanics, and vendor personnel were not adequate to compensate for the numerous flexibilities allowed in the vendor and licensee procedures.
The inspector reviewed the licensee's IRB report.
The inspector agreed with the IRB's conclusions and noted that the corrective actions proposed by the IRB appeared satisfactory.
The licensee revised the implementing WOT and PPH 8.5. 11 to provide more detail and specificity.
2. 1.2 Overturning of Barrel Containing Radioactive Filters On Sunday Hay 14, 1995, at 5:45 a.m.,
the shift manager notified the resident inspector that a shielded 55-gallon drum containing highly radioactive decontamination unit filters slid and fell off a transport cart.
The drum came to rest in the open west airlock doorway of the 441 foot level of the reactor building.
The bagged filters were partially exposed; however, the bags remained intact and leak free.
The shift manager indicated there were no surface or airborne contamination concerns and that no personnel had exceeded exposure limits.
He noted the area had been roped off and preparations were in progress to upright the barrel and its contents.
The senior resident inspector responded to the site.
NRC followup inspection of the licensee's planning, command, and control of the transport of the filters and the licensee's event evaluation is discussed in NRC Inspection Report 50-397/95-16, and enforcement action is under consideration.
2. 1.3 Conclusions Inadequate licensee communication, coordination, and evolution control led to these events.
The original procedures for the decontamination process were not adequate for safe, conservative operation of the equipment.
Management oversight was generally ineffective and, therefore, did not preclude these events.
No individuals exceeded exposure limits.
The licensee's IRB of the spill of contaminated liquid was thorough and addressed root causes.
Backcaround Because the licensee had seen small voltage oscillations in the output of DG3, the MOP associated with voltage control in the regulator was to have been replaced during Refueling Outage R10.
Due to a procurement error, the MOP for the automatic speed control portion of the governor was ordered.
When the error had been recognized, the licensee examined the HOP of the speed governor and determined that it too required replacement.
The HOP of the governor was replaced on Hay 5, 1995, using WOT UJ45 01.
Because the licensee did not have a replacement MOP for the voltage regulator, a visual exam was planned to assess that MOP's performanc.2.1 Fire in the HPCS Diesel Room At 4:33 p.m.
on Hay 23, 1995, using PPH 2.7.3,
"High Pressure Core Spray Diesel Generator,"
the licensee started DG3 with the regulator in manual to retest and, if necessary, adjust the MOP.
The licensee did not consider DG3 operable and was not relying on DG3 for Technical Specification requirements.
DG3 started as expected and accelerated to a rated speed of 900 rpm.
At 4:46 p.m., the equipment operator placed the regulator in automatic in accordance with WOT UJ45 02, which provided instructions for adjusting the MOP.
DG3 speed rapidly slowed to 425 rpm.
At that point, the system engineer directed electricians to adjust the MOP to increase DG3 speed to 900 rpm.
The electricians had difficulty adjusting the MOP and could not obtain a speed response to the adjustments.
At 4:55 p.m.,
one of the electricians noticed an acrid white smoke coming from the voltage regulator potential transformer cabinet.
The equipment operator performed an emergency shutdown of DG3 and notified the control room of smoke.
Control room operators announced the fire in the DG3 room over the general announcing system and called away the fire brigade.
The resident inspectors observed the licensee's response to the fire from the control room and the DG3 area.
The smoke subsided as soon as DG3 was stopped and power was removed from the regulator.
Upon inspection, the licensee found that the instrument and metering potential transformer had failed.
The licensee initiated PER 295-0621 to further investigate this event.
2.2.2 The Licensee's Preliminary Event Evaluation and Corrective Actions The licensee's investigation into this event found that the instrumentation and metering transformer had failed because the transformer had exceeded its rating.
The transformer had a continuous volts per hertz rating of 110 percent and an emergency rating of 125 percent.
The transformer operated at 160 percent for 9 minutes, resulting in the failure.
The licensee concluded that the work order had omissions of relevant information.
The work order did not provide adequate instructions or precautions associated with the operation of DG3 while attempting to adjust the HOP.
The licensee's investigation also concluded that an error had been made when electrically connecting the MOP during static testing.
This error resulted in DG3 not increasing in speed when the electricians attempted to adjust the MOP.
As corrective actions, the licensee spoke with the vendors that manufactured the DG3 components that could have been damaged by this event.
Prior to operating DG3, the licensee tested these components according to the vendors'ecommendations.
The licensee examined the HOP associated with the voltage regulator and found that a coupling in the HOP had come loose.
When the coupling was tightened, the voltage oscillations were eliminated.
After the repairs, DG3 operated as
expected.
To prevent recurrence of this event, the licensee plans to develop a detailed training session discussing the event and the operation and maintenance of the HOP.
The licensee concluded that the root causes of this event were the incorrect wiring of the HOP during static testing and inadequate work instructions in WOT UJ45 02.
2.2.3 Inspectors'bservations The inspector in the control room noted that, while plant safety was not challenged, operator response to the event indicated a need for improved crew command and control by the following:
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A control room operator (CRO) took over as lead panel CRO without an adequate turnover.
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The shift manager and the shift technical advisor left the control room to go to the DG3 room.
The shift technical advisor left to take pictures of the damage.
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Periodic briefings of the event were not conducted in the control room.
The control room received annunciators for HPCS 125 Vdc battery low voltage and battery trouble.
The voltage indication for the HPCS battery indicated zero.
Approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the fire brigade verified that the smoke had stopped and the system was isolated, the control room supervisor obtained HPCS battery status.
The inspector had the following observations at the scene of the fire.
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Even though the fire brigade response to the HPCS diesel room was timely, the fire brigade did not make a timely assessment of the situation and secure the area.
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Personnel in the DG3 room did not evacuate the DG3 room upon the CRO's announcement of the fire.
The inspector noted that some DG3 cabinets contained polychlorobiphenyls (PCBs).
2.2.4 Safety Significance The fire in DG3 had minimal safety significance since the licensee had not been relying on DG3 to meet Technical Specification requirements.
2.2.5 Conclusions The inspectors considered the licensee's evaluation to be less than comprehensive and thorough.
The fire in the DG3 regulator resulted from a combination of inadequate static testing of the HOP, inadequate work order
instructions, and poor coordination between the system engineer, the equipment operator, and the control room.
The licensee's response to the fire, while adequate, had deficiencies in command and control both in the control room and at the scene.
The licensee appeared not to always have effective turnovers and did not frequently brief the event in the control room.
Nonessential personnel did not evacuate the DG3 room and the fire brigade did not conduct a'timely assessment of the fire.
2.3 SDC Secured for Greater than 2 Hours 2.3.1 SDC Secured in Excess of Technical Specification Limits On May 12, 1995, a
CRO discovered that residual heat removal (RHR)
SDC had been secured for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 5 minutes in an 8-hour period.
Technical Specification 3.9.11.1 requires that at least one loop of the RHR system in the SDC mode shall be operable and in operation with at least one operable RHR pump and one operable RHR heat exchanger.
The RHR pump may be removed from operation for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per 8-hour period.
Immediate NRC followup of this issue was documented in NRC Inspection Report 50-397/95-14.
As corrective action, the licensee formalized the requirement to record the duration of securing SDC.
The violation of TS 3.9. 11. 1 was not cited because the criteria in paragraph VII;B.(2) of Appendix C to
CFR Part 2 were satisfied.
2.3.2 Additional Inspector Followup Action b of Technical Specification 3.9.11.1 states that, with no RHR SDC mode loop in operation, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature at least once per hour.
Following the NRC's initial inspection, the licensee concluded that an alternat'e method of decay heat removal, natural circulation, had been established.
The licensee based this conclusion on a General Electric calculation 'that had been performed for the previous refueling outage, The licensee also noted that the operators had been monitoring reactor coolant system temperature at least once per hour using the inlet temperature to the RHR heat exchanger.
The inspector questioned relying on hourly readings from the RHR heat exchanger inlet temperature for monitoring reactor coolant system temperature since these temperatures were not representative of reactor coolant system temperature when there was no forced circulation.
The licensee agreed with the inspector.
Approximately 3 weeks after this event, the licensee obtained fuel pool cooling temperatures from the transient data acquisition system computer that indicated natural circulation flow had been established.
The plant manager committed to implement a procedure that establishes the plant conditions that natural circulation can be used as an alternate means of decay heat removal and identifies the proper temperatures for monitorin.3.3 Conclusions Operator informality and the lack of procedural requirements led to this event.
The licensee's initial investigation into this issue was not insufficiently critical to identify that operators had been monitoring a
nonrepresentative temperature to assess reactor coolant system temperature.
PLANT OPERATIONS (71707, 92901)
3. I 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 3.2.2 Operating Logs and Records The inspectors reviewed operating logs and records against Technical Specification and administrative control procedure requirements.
The inspectors identified that operators had not been recording reactor coolant system temperatures when SDC had been secured for reactor vessel component inspections.
The licensee identified that the operators had not effectively tracked the temperatures during the time used in securing SDC.
These two issues are discussed in paragraph 2.3.
3.2.3 Honitoring Instrumentation The inspectors observed process instruments for correlation between channels and for conformance with Technical Specification 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), Technical Specification, 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
-11-attentive to duties.
The control room was observed to be free of distractions, such as nonwork-re'1ated radios and reading materia'js.
3.2.5 Equipment Lineups The inspectors verified that valves and electrical breakers were in the position or condition required by Technical Specification 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 Technical Specification limiting conditions for operation was verified by direct observation.
The inspectors identified no discrepancies during the NRC's independent checks.
On Nay 28, 1995, the licensee's second verification of a clearance order identified that nine breakers were out of position.
The licensee initiated PER 295-0660.
The licensee's investigation found that a single individual, who had failed to self-check, had been responsible for all nine errors.
The inspector walked down the mispositioned breakers with the operations manager on May 30, 1995.
The inspector identified no unusual circumstances that could have led to the errors.
However, the inspector found that all nine breakers were still in the incorrect position which was different from the corrective actions identified in the PER that stated "first and second breaker lineup verifications were done again."
The inspector notified the operations manager of the apparent error in the PER.
The operations manager found that the shift support supervisor who wrote the PER had intended to reperform these lineups during his shift, but did not complete the actions due to other priorities.
The shift support supervisor failed to adequately convey the need to reposition the breakers during his turnover.
Subsequent to the inspector's discussion with the operations manager, the licensee correctly positioned the breakers.
The inspector reviewed the licensee's corrective actions and determined that the actions were satisfactory.
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.
The inspectors noted the following issues with respect to clearance tagging.
The inspectors observed a danger tag on the floor, inside a contaminated work area.
The danger tag (15) was associated with Clearance Order (CO) 95-03-0101 and identified Valve CRD-V-737 as being closed.
When an operator checked the valve, he found it closed and re-attached the tag.
The tag appeared to have been tom from the valve, probably due to work in the area.
The licensee initiated PER 295-0619 to document the inspector's finding.
This observation had no safety significance because the valve in question had not been repositione During this inspection period the licensee initiated more than a dozen PERs for problems with the tagging processes.
This underscores the continuing problem with the CO process.
The licensee enrolled the individuals involved with these errors in a training program to improve their self-checking and attention to detail.
The licensee's actions to address clearance order and tagging problems at WNP-2 will be discussed at a conference scheduled for July 28, 1995, in response to issues identified in NRC Inspection Report 50-397/95-15.
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; however, the inspectors identified a problem concerning properly posting entry into the wetwell for foreign material exclusion.
On May 24, 1995, the inspector noted that the wetwell was open and personnel were performing work inside the wetwell.
While the area was posted as a high radiation area and contaminated area, it was not posted as a foreign material exclusion area.
The inspector noted that PPM 2.3.9,
"Personnel Entry Into the Wetwell," references PPM 10. 1. 13,
as applicable for entries into the wetwell.
PPM 10. 1. 13, paragraph 7.2.5, requires areas such as the wetwell to be roped off and posted with the signs referenced in the procedure.
The inspector notified the shift manager.
The shift manager documented the inspector's concern in an internal instruction form.
The licensee took action to properly post the wetwell to correct the problem.
The inspector noted that, although the area had not been posted as required, a
security guard was posted at the entrance and was keeping the foreign material exclusion log.
Therefore, this observation had no safety significance.
This observation indicates the continued need for strict attention to detail in implementing procedures.
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 applicabl 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 (LPCS)
High Pressure Core Spray RHR Trains A and B
Standby Gas Treatment (SGT)
Standby Liquid Control 125V DC Electrical Distribution, Divisions 1 and
Dates Hay
May 17,
Hay 17,
May 17,
Hay 17,
Hay 4, June
April 26 May 4 250V DC Electrical Distribution Hay
The inspectors noted that the engineered safety features systems were generally in good material condition and were aligned in accordance with applicable licensee procedures for the portions walked down
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The inspectors had the following observations during the tours.
3.3.1 Temperature Monitor Past Its Calibration Due Date On Hay 23, 1995, during a tour of the RHR A pump room, the inspector found that the digital room temperature monitor had a calibration sticker with a due date of April 20, 1995.
The inspector notified the shift manager.
The shift manager contacted the calibration lab personnel, who reviewed the calibration records of the instrument and determined that the calibration could be extended to October 1995.
The licensee found that this indicator was not used to meet Technical Specification requirements.
This observation emphasizes the need for the calibration lab to ensure adherence with calibration due dates.
3.3.2 Improper Restraints for Compressed Gas On June 2,
1995, during a tour of the reactor building, the inspector found that the restraints for the compressed gas cylinders were not attached
-14-properly.
Two of the bolts that were required to be tightened were hanging from a nearby chain.
The inspector informed the shift manager, who initiated PER 295-0691.
The licensee corrected the problem with the restraints.
The licensee noted that, although the configuration was degraded, the compressed gas cylinders were adequately restrained to prevent a missile hazard.
The licensee's evaluation and corrective actions appeared satisfactory.
This was a repeat observation and indicates that continued management attention is necessary to ensure the staff implements adequate safety with respect to storage of compressed gas cylinders.
3.3.3 Loose Test Port for SGT On June 2,
1995, during a walkdown of the SGT system, the inspector noted that test Port Rll on SGT Unit 1B1 was loose.
Ouring extended postaccident SGT operation, the loose test port could work itself off and cause the SGT effluent to be released to the reactor building.
The inspector notified the shift manager of the loose test port.
The licensee tightened the test fitting as required.
The licensee found that this test port had been removed during recent surveillance testing, but had not been adequately tightened following the test.
3.4 Conclusions Management has not been fully effective in assuring that employees exercise the appropriate attention to detail in day-to-day plant activities.
Numerous instances of inattention to detail continue to occur at WNP-2, which is exemplified by CO and tagging errors, incorrect positioning of plant components, errors in storage of compressed gas bottles, and equipment that is beyond its calibration due date.
ONSITE ENGINEERING (37551, 92903)
The inspectors performed inspections of the following onsite engineering related activities during this inspection period:
4. 1 Service Water Pum Vibration
~Back round On Hay 7, 1995, the iicensee identified high vibration leveis for service water (SW)
Pump SW-P-1B.
The motor for the SW pump had been replaced during Refueling Outage R10.
The inspector performed followup of this issue to assess the potential effects of the vibration on long-term operability.
Measured vibration levels for Pump SW-P-1B were as high as 7 mils.
General Electric Motor Manual GENE-L009-0925 recommends pump shutdown at 4 mils.
Using values recommended in the licensee's in-service testing program, the vibration levels placed Pump SW-P-1B in the "Alert" range, requiring increased monitoring.
The licensee performed a prompt operability assessment and a
-15-followup assessment of operability (FAO).
The FAO concluded that the pump was operable but degraded.
The licensee performed initial load assessments based on the higher vibration levels and determined that increased vibration levels did not indicate immediate motor failure.
The inspector reviewed the licensee's calculations and FAO.
The inspector noted that the design basis of the SW pump requires that it operate for 6 months postaccident for long-term heat removal.
The inspector was concerned that the FAO had not considered this design basis.
The licensee stated that the FAO was only valid for operational Modes 3, 4, and 5.
The licensee also stated that they intended additional actions prior to operating in Nodes
and 2.
The licensee noted that the new motor weighed 3000 pounds less than the original motor.
The licensee performed vibrational analysis calculations and noted that installing the new motor resulted in introducing resonant frequencies during pump operation that caused the 7 mil vibration.
The licensee contacted the vendor, who agreed with the licensee's assessment.
The design engineering group then initiated a basic design change to add static weights to the SW pump to reduce the vibration.
The licensee completed this design change and retested the vibration levels of the SW pump.
The vibration levels were measured at approximately 1.5 mils, well within the vendor's recommendations.
The inspectors reviewed the licensee's test data and design change and found all to be satisfactory.
Engineering personnel effectively resolved high vibration levels for Standby Service Water Pump SW-P-IB, although a more aggressive questioning of the effects of the difference in the weight of the motors may have avoided this problem prior to the motors installation.
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.
The inspectors noted that a high number of fire impairments existed for which fire tours were being conducted because of concerns with Thermo-Lag and fire seals and the number of propped fire open fire doors to support work.
5.2 Radiation Protection Controls The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with radiation work
-16-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.
The licensee initiated
PERs concerning improper personnel entry into radiologically controlled areas.
These issues will be addressed in NRC Inspection Report 50-397/95-16.
As of the end of the inspection period, the licensee was well under their exposure goals for the outage, projecting that total exposure would be approximately 85 percent of the goal, The licensee attributes the reduced exposure to extensive installation of temporary shielding and the elimination of some high exposure work.
On May 22 and 24, 1995, the inspectors noted concerns with contamination controls.
In the LPCS pump room, the inspectors noted that a radioactive yellow polyethylene bottle had a hose that went to the overhead.
When the inspectors traced the hose, they found that the hose was connected to a
radiological catch that was turned face down, incapable of directing liquid to the bottle.
The inspectors notified health physics (HP)
and an HP technician who uprighted the catch.
The HP technician performed smear surveys and verified that no contamination existed.
In the control rod drive (CRD)
pump room, the inspector noted another overturned radiological catch and informed health physics.
No contamination was found in this case either.
5.3 Plant Housekee in The inspectors observed plant conditions and material and 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 functiona The inspectors reviewed chemical analyses and trend results for conformance with TS and administrative control procedures.
Plant chemistry was satisfactory during this inspection period.
5.7 Conclusions Plant support performance was generally good during this inspection period.
SURVEILLANCE TESTING (61726)
The inspectors reviewed Technical Specification surveillance tests on a
sampling basis to verify that:
(1)
a technically adequate procedure existed for performance of the surveillance tests; (2)
(3)
the surveillance tests had been performed at the frequency specified in the Technical Specification and in accordance with the Technical Specification surveillance requirements; and test results satisfied acceptance criteria or were properly dispositioned.
6.1 DG1 Loss of Offsite Power LOP Test 6. 1. 1 DG Surveillance Testing On May 23, 1995, the licensee conducted Surveillance Procedure 7.4. 1. 1.2.5B,
"Standby Diesel Generator DG1 Loss of Power Test," Revision 7.
This procedure involved testing of various features of DG1, including the simulated LOP and load shed test.
The inspector observed the following items associated with the pre-job briefing:
~
Each individual associated with the test was given a specific assignment.
~
Precautions and limitations were discussed.
The inspector observed the following during conduct of the surveillance test:
Participants asked several questions to clarify equipment conditions.
Control room operators, who had not participated in the pre-job brief, were added by the control room supervisor to assist in monitoring control board equipment actuation ~
Operators were frequently distracted by personnel entering the control room because access had not been limited during the testing and by an excessive number of phone calls.
~
Control room operators used good self-verification techniques (i.e.,
checking switch labeling with the procedure several times prior to manipulation and ensuring equipment actuated as expected),
good annunciator call out, and good repeat backs.
6. 1.2 Surveillance Test Data Review The inspector reviewed the LOP and load rejection portions of the testing procedure to determine if the testing conformed to Technical Specification requirements.
All referenced Technical Specifications were found appropriately addressed by the correct testing and acceptance parameters.
On May 25 the inspector met with the DG electrical system engineer to review transient data acquisition system (TDAS) data collected for the surveillance to determine if it satisfied the acceptance criteria.
Data'oints for 16 signals were selected as specified by Attachment 10. I of Procedure 7.4.8.1.1.2.5B.
The data points satisfied the acceptance criteria.
The inspector reviewed three steps from the surveillance procedure that were
~
~
~
~
~
~
~
identified as Technical Specification acceptance criteria (Steps 7.6.39d, 7.6.39e, and 7.7. 16).
The inspector identified the following discrepancies:
~
DG1 electrical loading on TDAS was only 1250 kW versus the procedural requirement of 1.4 HW (Technical Specification minimum of 1377 kW).
~
Large differences were noted between the kW readings on DGI TDAS and control board meter (3800 kW versus 4.4 HW, respectively, Step 7.7.23).
6. 1.3 Instrument Discrepancy Resolution In discussions with the system engineer and his supervisor, the inspector found that neither were aware of the discrepancy between the DG1 control board MW meter and the TDAS kW indication.
The inspector requested that the licensee resolve the discrepancy.
Initially, the supervisor of electrical system engineering told the inspectors that the TDAS DG kW output was the only TDAS point that could not be calibrated and that the point was not used as a
TS acceptance criteria.
In reviewing the procedure, the inspector found that TDAS electrical loading was used in Step 7.6.39e and was identified in the procedure as a Technical Specification acceptance criteria'he inspector requested that the licensee more thoroughly address his concern.
Subsequently, the electrical system engineering supervisor indicated that the procedure was in error because the incorrect step had been identified as the
-19-acceptance criteria.
Step 7.6.40, which records control board indication for OG loading, was actually used to satisfy Technical Specification 4.8. 1. 1.2.e.9 but not Step 7.6.39e.
The inspector questioned whether the TDAS DG kW output meter was the only TOAS point that could not be calibrated.
The supervisor stated that he believed that was correct, but that he would verify it.
The inspector reviewed the data for the last two calibrations of the control board diesel generator HW meters.
The calibration data sheets for OG1 and DG2 control board diesel generator HW meters (DG-W-OG1 and DG-W-DG2) also included calibration data for TDAS Computer Points 226 and 258.
TDAS Point 226,
"DG1 kW Output,"
was one of the computer points used for DG1 LOP surveillance test.
The "as found" test data for OG1 for both TDAS and the control board meter showed both instruments were out of calibration (+ or 1 percent).
The instruments were recalibrated within required tolerance.
The TDAS calibration data contradicted what the supervisor had stated earlier the TDAS kW meters apparently could be calibrated.
The inspector requested that the supervisor more thoroughly address this issue.
On Hay 31 the inspector met with the TDAS system engineer.
The system engineer stated that he first became aware of a potential problem with TDAS computer points for diesel generator electrical output several weeks earlier when they were conducting testing on DG2.
Circuitry construction for this instrumentation function consisted of having to measure the voltage drop across the meter itself versus the normal use of a dropping resistor; therefore, the voltage changes were extremely small (milli-volts).
The system engineer stated that TDAS DG1 kW output could be calibrated but, based on his engineering judgement, the design did not lend well to maintaining calibration and should not be considered a good data point.
When asked, he stated that no historical data was referenced to support his judgement and he was unsure of the current status of the TDAS point.
To determine which indication was accurate, the licensee performed a
calibration check on DG1 control board MW Heter DG-W-DG1 and TDAS Computer Point 226.
Meter DG-W-OG1 was within calibration and TDAS Computer Point 226 was out-of-calibration low.
The computer point was up to 14 percent low at the upper end of the output band.
The licensee also produced a copy of the calibration done on Hay 16 on TDAS Computer Point 226.
This calibration showed TDAS was up to 19 percent high on the upper end of the band.
The system engineering supervisor explained that the cause for the.inaccuracies was due to the design of this point as explained above.
He explained that ambient conditions and small current changes can greatly aFfect the response of this data point, making it inherently less accurate.
He noted that he had not provided the correct information on the calibration of TDAS because he failed to understand the explanation provided to him by the TDAS system engineer concerning TDAS Computer Point 226.
The licensee initiated a
PER to document the problems observed with the TDAS DG electrical load points and to correct the procedure so that a reliable
-20-generator load instrument would be identified as acceptance criteria for Technical Specification 4.8. 1. 1.2.e.9.
The system engineering manager indicated that the PER would look at other TDAS points to ensure that a
generic problem does not exist with the overall reliability of TDAS data points.
6.2 Other Observed Surveillances The inspectors observed portions of the following surveillance tests on the dates shown:
PPM 7.4.8.2. 1. 1.7A,
"DG-2 LOCA Testing" (Hay 11)
and PPH 7.4. 1. 1.2.5B,
"DG-1 Loss of Power Testing" (Hay 23).
The inspectors identified no discrepancies in the performance of these surveillances.
6.3 Conclusions Overall, surveillance testing was performed properly and in accordance with procedures.
The DG1 LOP testing satisfied the portions of Technical Specifications reviewed.
The review of TDAS test data by the system engineer was not adequate since the discrepancy with electrical loading and the surveillance procedure error were not identified.
The system engineer and the electrical system supervisor lacked a thorough questioning attitude during the resolution of the differences between the DGl TDAS and control board indication.
NAINTENANCE 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 Dates Performed Replace Containment Electrical Penetration X-101-A Hay
RF1201, Disassemble HPCS Diesel Generator Preventative to Perform Preventive Maintenance Tasks Hay 5-8 PG7902, Refurbish RCIC-V-110 PD5803, Replace CSP-V-3/4 Refurbish CRD-V-14B Hay
Hay
Hay 22
-21-The inspectors noted that these maintenance activities were performed and documented properly.
The inspectors had the following observations.
On Hay 22, 1995, during work on Yalve CRD-Y-148, the inspectors noted that the work included grinding operations.
During the work, the inspectors noted that the licensee had a fire watch stationed and had a "Cutting, Welding, and Grinding" permit to perform the work.
The inspectors noted that the licensee was using green polyethylene bags to cover up the other control rod drive components in the area.
The inspectors were concerned that these materials were combustible and could lead to a fire if they were left in the vicinity of the cutting operations.
When the licensee temporarily stopped work, the inspectors left the immediate area, The inspectors returned to the area of the CRD valve work approximately IO minutes later.
The inspectors walked the area in the vicinity of the CRD pump where the grinding had been performed.
The inspectors observed the axial ends and the front of the CRD pump.
They observed no personnel in the area.
In particular, the fire watch was not present.
The inspectors stayed in the area.
While waiting for the craftsmen to return, the inspectors reviewed the
"Cutting, Welding, and Grinding" permit at the worksite.
The permit indicated that a firewatch was required for 30 minutes following any grinding operations.
When a craftsman returned approximately 5 minutes later, the inspectors questioned the craftsman as to who was the firewatch.
The craftsman replied that he was the fire watch, and he stated that he had left the area for a few minutes to make a phone call.
The craftsman resumed the fire watch and the inspectors exited the area.
The inspectors informed the fire marshall and the maintenance manager.
The fire marshall initiated PER 295-0604 to document the inspectors'oncern and to propose corrective actions.
The licensee held a "Timeout" with maintenance personnel to discuss cutting, welding, and grinding operations.
Sometime after the inspectors raised this issue, the licensee spoke with the Raytheon craftsmen involved with this observation.
The craftsmen indicated that, for the 30 minutes following the grinding, a firewatch was always present.
The craftsmen indicated that, during the time that the one craftsman was making a phone call, a second craftsman was acting as the fire watch.
The second craftsman indicated that he had been kneeling at the end of the CRD pump motor.
The, inspectors noted the difference between their initial observations and conversation with the craftsman and his subsequent statement.
Table 6.4.a of PPN 1.3. 10, "Fire Protection Program Implementation," requires that during "spark or slag producing operations (e.g.,
welding and cutting)"
a
"trained fire watch" be in place and that the "fire watch remains at the job site for
/> hour after work is done."
Section B.3 of the WNP-2 fire protection program states,
"Work involving ignition sources is done under controlled condi tions."
Because the firewatch did not remain in the area for
-22-1/2 hour following grinding, this appears to be a violation of License Condition 2.C.(14) of the WNP-2 operating license (Violation 397/9515-01).
REFUELING OBSERVATIONS (60710)
The inspector observed sample portions of the licensee's refueling activities.
The inspector observed the licensee's conformance to administrative procedures, Technical Specifications, foreign material controls, and radiological controls.
The inspector noted that refueling was performed in a
formal and deliberate manner.
Communications between refueling personnel and the control room were observed to consistently include repeat backs.
The refueling senior reactor operators provided good leadership in adhering to procedures and self-verification.
The licensee completed full core verification and noted that no errors were made in positioning or orienting fuel assemblies.
The inspector reviewed the tapes of the full core verification and identified no problems.
On Nay 4, 1995, the inspector identified one minor issue when the control room contacted the refueling bridge and requested that the crew temporarily suspend refueling to support required surveillance testing.
The refueling senior reactor operator stopped refueling at this time with a bundle suspended from the refueling mast and over the spent fuel pool for the duration of the surveillance testing.
The inspector discussed this issue with the plant manager who stated that, although this action was allowed by procedure, it was not the most conservative action to take.
The inspector concluded that, overall, refueling operations during Refueling Outage R10 improved significantly from the previous refuelings.
Licensee management was thoroughly involved in preparation for refueling and effectively communicated its expectations to all of the crews.
PLANT HARDWARE MODIFICATIONS TO REACTOR VESSEL WATER LEVEL INSTRUMENTATION (TEMPORARY INSTRUCTION 2515/128)
9. 1 Back round InFormation In Generic Letter 92-04,
"Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," the NRC staff expressed concern that noncondensible gases may become dissolved in the reference leg of boiling water reactor (BWR) water level instrumentation and lead to a false high level indication after a rapid depressurization event.
NRC Bulletin.93-03 requested BWR licensees to implement hardware modifications necessary to ensure that the level instrumentation is of high functional reliability for long-term operation.
The objective of this Temporary Instruction 2515/128 inspection was to verify and evaluate licensee implementation of these hardware modifications.
The licensee completed the reactor water level instrumentation (RVLIS) backfill modification in July 199.2
CFR 50.59 Safet Evaluation of the Modification Initial NRC review of the licensee's
CFR 50.59 safety evaluation of the RVLIS backfill modification was performed as part of NRC inspection 50-397/94-02.
The inspectors considered the evaluation adequate, except for a concern that the licensee had not considered the potential for blockage of the instrument line to the condensing pot and the consequences of an ensuing transient caused by resultant pressurization of the line by the backfill system (Unresolved Item 50-397/9402-01).
Further review by the NRC concluded that this was not a credible event.
The unresolved item was closed in NRC Inspection Report 50-397/95-03.
The following were some of the significant issues considered by the NRC in arriving at the conclusion:
the subject instrument line is designed to the requirements of Seismic Category I and the ASME Boiler and Pressure Code,Section III; the licensee welded a device to the root valve on the line to prevent inadvertent closure; and the line is located sufficiently above the floor to prevent plant personnel from inadvertently crimping the line.
9.3 Review of the Modification Packa e Includin Pre-Installation and Postinstallation Testin 9.3.1 Backfill Flow The inspector interviewed licensee personnel and reviewed test records in determining that premodification testing was extensive and established an adequate backfill flow rate.
The inspector also noted that WNP-2 engineers had been heavily involved in industry test programs and that industry testing was conducted on a model of a WNP-2 line suspected to be vulnerable to notching and degassification.
The inspector considered the licensee's extensive testing and industry involvement a strength, The inspector noted that the lower value of the backfill flow, 0.12 gph, was based on adequate flow to prevent accumulation of noncondensable gases which could be reliably and accurately measured with the installed flow instrumentation.
The upper flow limit, 0.48 gph, was established to keep flow sufficiently low to prevent excessive thermal cycling of the associated reactor vessel nozzle.
Postmodification testing'established that the required flows could be maintained.
The inspector also noted that the licensee checked and recorded local flow indication of the backfill lines daily.
In reviewing the daily logs for backfill flow rate, the inspector noted some cases where flow rate was outside of the criterion which the licensee had established for acceptable flow rate.
In such cases, the licensee would adjust the needle flow valves on the line to reestablish an acceptable flow rate.
Most cases of unacceptable flow occurred as a result of low flow.
The licensee postulated that the low flow may have been as a result of small particles lodging around the needle valve flow area.
A simple adjustment of valve position was sufficient to reestablish adequate flow.
The inspector considered the measures to address low flow were adequate because flow was checked daily and adjusted, if necessary, whereas a complete absence of flow
-24-for many days would be necessary to introduce an appreciable amount of noncondensible gases to affect discrepancies in reactor water level indication.
The inspector also noted two instances where flow rate was observed to exceed the flow rate acceptance criterion.
The inspector was concerned because the licensee did not require that a
PER be generated for such cases.
Specifically, the inspector was concerned that a high flow rate could contribute to excessive thermal cycling of the associated reactor vessel nozzle.
In response to the inspector's concerns, the licensee revised their procedures to include a requirement to initiate a
PER when flow rate is observed to exceed the flow rate acceptance window.
9.3.2
,Measures to Prevent Inadvertent Closure of Reference Leg Manual Isolation Valves As noted in Section 9.2, the licensee welded a device to prevent closure of the manual isolation valve in one of the reference legs for which valve closure could put the plant in an unanalyzed condition with potential significant consequences adverse to safety.
The inspector checked the licensee's actions to prevent closure of the manual isolation valves on the other reference legs and noted that the licensee had secured the other manual isolation valves in the open position by means of a chain and lock for the valve handwheels.
The inspector verified that administrative control of these locked valves was being maintained by PPM 1.3.29, Revision 23,
"Locked Valve Checklist."
The inspector considered the control of the open position for these valves to be adequate since the consequences of their closure were of low safety significance and potential events associated with their closure would not have placed the plant in an unanalyzed condition.
9.3.3 Separation of Safety/Nonsafety Systems Addition of the backfill line from the CRD system to the reactor vessel level reference leg involves the connection of a nonsafety system, the CRD, to a
safety system, the RVLIS.
The licensee's approach to the safety/nonsafety system interface was to design the nonsafety-as well as the safety-related portion of the line in accordance with ASME Boiler and Pressure Vessel Code,Section III, requirements supported as a Seismic Category I line.
The inspector considered this approach acceptable since this was consistent with the licensee's committed design requirements.
9.3.4 Backfill Line Containment Isolation The inspector noted that the licensee had included excess flow check valves in the design of the backfill lines.
The excess flow check valves appeared capable of isolating flow in the event of a line break.
However, according to the licensee, they had not taken credit for these valves in their safety analysi.3.5 Procedures The inspector performed a limited review of the following licensee procedures affected by the backfill modification to the RVLIS:
PPH 1.3.29, Revision
PPH 3.1.10, Revision
PPH 3.2. 1, Revision
"Locked Valve Checklist"
"Operating Data and Logs"
"Normal Shutdown to Cold Shutdown" PPH 3.2.2, Revision
"Normal Shutdown to Hot Shutdown" PPH 8.3,291, Revision
PPH 10.27.64, Revision
"Continuous Backfill from CRD-Preoperational and Startup"
"RPV Level Instrumentation Reference Leg Purge System Operation" The procedures appeared to adequately address backfill system operation, including placing the system in service, flow rate surveillance, and adjusting flow rates when necessary.
In reviewing the operating procedures, the inspector noted that the licensee had established an allowed outage time (AOT) of 30 days for the continuous backfill system to be out of service.
According to the licensee, the AOT was based on past observations of notching and degassification.
Data taken from one of the lines before implementation of the continuous backfill modification (thought to be the most susceptible to collection of noncondensable gases due to geometric configuration),
showed a maximum deviation of 6 inches after 45 days of continuous operation.
The licensee and the inspector acknowledged that small leaks in the reference legs could also contribute to notching phenomena in some cases.
The inspector also noted that the data being used by the licensee was taken under controlled depressurization conditions and might not account for level deviations that could occur following a rapid depressurization associated with a postulated loss of coolant accident.
The licensee maintained that a 30-day AOT was reasonable based on the available information and pointed out that, since geometries of each of the reference legs differ, the likelihood of notching or degassification occurring on all lines at the same time was extremely remote.
Furthermore, it was noted that all automatic emergency core cooling system actuations occur significantly above 450 psig, the point at which notching and degassification becomes a
concern.
The inspector noted that the licensee's operating procedures include special provisions and cautions when an RVLIS line continuous backfill outage exceeds the 30-day AOT and that licensee operators have received training on recognition and response to indications of RVLIS level deviations.
Based on the foregoing information, the inspector considered the licensee's AOT and related provisions in the operating procedures to be adequat FOLLOWUP (92901, 92902, 92903, AND 92904)
The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions in response to previous open items.
10.
Closed Violation 397 9345-09:
"Failure to Follow Procedures Durin Testin of the Avera e Power Ran e Monitors APRMs
"
This violation involved the failure of licensee instrument and control ( ILC)
technicians to adequately perform a portion of surveillance procedure PPM 7.4.3. 1. 1.48,
"APRM CHANNEL F RUN MODE - CFT/CC."
A step in the procedure required that, following an adjustment of a potentiometer, the indicating lamp for the high power scram be verified as on.
The technicians performing the surveillance mistakenly verified that the high power scram light was on when, in fact, they were looking at the flow-biased scram light, As a consequence, later in the performance of the surveillance, the technicians were unable to verify an indication of the high power scram on the process computer alarm typer printout.
Of further significance, when the shift technical advisor and the shift manager were informed that the high power scram indication had not printed on the process computer alarm typer, they incorrectly concluded, without sufficient investigation.
that the alarm typer was the problem.
Licensee personnel did not take subsequent actions to determine the cause of the problem, failure to adjust the potentiometer to the required high power scram trip point and failure to obtain indication, until questioned by the NRC inspector who was observing the surveillance.
In response to the Notice of Violation, the licensee discussed the cause of the event and proposed corrective actions to prevent recurrence.
The licensee determined the cause of the event was the ILC technician failing to adequately self-check and the shift manager failing to verify his initial assumptions.
The corrective actions included the following:
counseling of the ILC technicians to practice self-checking; discussing the event with I&C personnel; counseling of the shift manager to be more proactive in resolving problems; briefing operating crews on lessons learned; enhancing the procedures to clarify the requirements for trip indications; and reviewing APRM surveillances completed since July 1993 to determine that no similar problems with the alarm typer were noted.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequate.
10.2 Closed Violation 397 9402-02:
"Failure to Verif Manual B
ass Valves Closed" This violation was due to the licensee's failure to ensure that the manual bypass valves for excess flow check valves were verified closed or locked in their closed position in accordance with the licensee's TS requirements.
The
-27-licensee determined the root cause of the violation was an inadequate procedure because it failed to include the correct equipment piece numbers for the valves.
The licensee's corrective actions included the following:
verifying that the valves were closed; revising the surveillance procedure to include the correct equipment piece numbers for the valves, and training those individuals involved in the procedure revision effort to emphasize management expectations regarding responsibilities associated with technical review, procedure revisions, and the verifications and validation process.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequate.
10.3 Closed Violation 397 9415-01:
"Failure to Perform a
Prom t 0 erabilit Assessment" This violation concerned the licensee's failure to perform a prompt operability assessment following identification of significantly degraded BUNA-N diaphragms in scram solenoid pilot valves for Control Rods 02-19 and 14-55, a condition impacting equipment operability.
The licensee determined that the cause of the event was the system engineer erred in his judgement that an operability determination was not needed.
The licensee's corrective actions included:
completing the operability assessments; involving the engineer responsible for the operability in the preparation for the enforcement conference concerning this issue; meeting with the engineering and technical staffs to emphasize management expectations concerning documentation of operability issues; and revising PPH 1.3. 12, the procedure which required prompt operability assessments, to address component as well as system operability.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequate.
10.4 Closed Violation 397 9415-02:
"Failure to Prom tl Identif and Correct Condition of Failed Com onents" This apparent violation identified a concern with the effectiveness of the licensee's corrective actions to address the control rod system problems.
An enforcement conference which included this issue was held in the Region IV office on June 30, 1994.
At that time, the licensee presented sufficient evidence for the NRC to rescind the violation in a July 22, 1994, letter to the licensee.
In the letter, the NRC requested that the licensee address steps taken to improve the timeliness of corrective actions.
The licensee adequately addressed this issue in its response to Notice of Violation 9415-0 LER REVIEWS (90712, 92700)
11. 1 Closed LER 397 93-28 Revision 0:
"Failure to Anal ze a Hi h Ener Line Break Located Outside Primar Containment" This LER documented an unanalyzed postulated high energy line break (HELB)
break in a reactor water cleanup (RWCU) system line located in the reactor building.
The licensee evaluated this deficiency for operability and determined that the plant could continue to operate safely.
In addition, the licensee also reviewed other piping systems for unanalyzed HELB breaks and requested permanent exclusion of the postulated break in the RWCU system.
The licensee submitted an amendment request, dated December 3,
1993, requesting exclusion of a single RWCU system HELB.
This request was denied by the NRC in a letter ("Denial of Amendment to Operating License for Exclusion of a High Energy Line Break in the Reactor Water Cleanup System for WNP-2")
dated July 7, 1994.
As part of the denial, the NRC stated interim operation could continue for one refueling cycle based on current piping condition and low piping stress levels.
However, the NRC stated that WNP-2 would need to complete the necessary analysis, design reviews, and plant modifications to address the postulated break prior to restart from the 1995 refueling outage.
As part of the resolution, the licensee submitted an amendment request, dated April 25, 1995, to address those areas of concern identified by the NRC.
The inspector reviewed this submittal which detailed design changes to the plant and additions to the Technical Specifications and compared them to Basic Design Change 94-0270-OA.
The inspector also discussed the design modification with the engineers involved in the design and implementation of the modification to ensure that the design modification and amendment request were comparable.
A review of WOT PF6707 detailed the postmodification testing procedures.
Two engineers interviewed stated that the postmodification testing was consistent with the amendment and met the proposed Technical Specification testing requirements.
Procedure 8.3.350,
"RWCU-FT-15 Post Modification Test and RTT (DIV 1)," Revision 0, and Procedure 8.3.351,
"RWCU-FT-16 Post Modification Test and RTT (DIV II)," Revision 0, were evaluated and determined to appropriately test response time.
The design modification was found to implement those hardware item additions and testing specified in the amendment request and were appropriate to address the LER concerns; however, the license amendment request, dated April 25, 1995, is currently under review by Office of Nuclear Reactor Regulation.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequat '
d
-29-11.2 Closed LER 397 93-30 Revision 2:
"Hissin Cable Tra Covers Discovered Durin the Electrical Power Racewa Walkdown" This LER described the discovery of numerous deficiencies in cable tray covers which resulted in noncompliance with electrical separation design criteria.
Initially, seven locations were identified where electrical raceway cable tray covers were not installed in accordance with electrical separation design criteria.
The inspector reviewed the licensee's corrective actions.
Three previous cable tray walkdowns had been conducted; however, the licensee was unable to determine if the deficiencies found were a result of plant construction or from work activities performed after construction.
Previous walkdowns did not use specially trained personnel.
The inspector's review of the separation criteria knowledge level of current plant personnel indicated numerous weaknesses.
As an immediate corrective action, the licensee established two teams of specially trained personnel who conducted walkdowns of all areas of the plant with specific criteria to identify discrepancies in electrical separation criteria requirements.
In addition, engineering reviewed design data and drawings and highlighted those locations where potential discrepancies existed.
A total of 166 deficiencies were identified.
In an attempt to prevent maintenance work from introducing electrical separation deficiencies, procedure changes now require personnel specifically trained in electrical separation criteria to perform electrical separation evaluations.
In discussion with a group of engineers responsible for the walkdowns, they identified five personnel currently trained in separation criteria.
A review of training records indicated initial training and one additional training session.
No requalification training was required; however, the licensee indicated that this group meets on a regular basis to discuss their work.
Discussions with plant personnel verified that only trained personnel were performing evaluations of electrical separation criteria.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequate.
11.3 Closed LER 397 94-01 Revision 0:
"Untested Fuel Transferred to the Emer enc Diesel Generator Fuel Oil Stora e Tanks" From December 14 through December 21, 1993, untested diesel fuel oil was transferred from the auxiliary boiler fuel oil storage tank to each of the three emergency diesel generator (EDG) fuel oil storage tanks which violated testing requirements of Technical Specification 4.8. 1. 1.2.c.
These fuel oil transfers resulted during the testing of the new fuel oil filter polisher system, which was connected to all EDGs'uel oil storage tanks and the auxiliary boiler auxiliary oil storage tas The licensee immediately tested the EDG fuel oil tanks, performed an operability assessment, and tagged shut the suction valves from the auxiliary boiler storage tank.
A design review and a safety evaluation was completed prior to realigning the auxiliary boiler fuel oil storage tank to the polishing system.
Other corrective actions included changing plant procedures; adding surveillance and maintenance requirements on the auxiliary boiler storage tanks to be consistent with EDG fuel oil storage tanks; and training on lessons learned relating to inter-ties and interactions between safety-related and nonsafety-related systems.
The inspector reviewed the safety evaluation and design change with the design engineer responsible for the
CFR 50.59 safety evaluation.
The inspector concluded that the actions taken by the licensee were appropriate.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequate.
11.4 Closed LER 397 94-06 Revision 0:
"Broken HPCS-Bl-OG3 Batter Fla Terminal Weld" This LER identified a broken weld between a flag terminal and the negative post of HPCS system battery HPCS-Bl-DG3 Cell 58.
The broken weld was identified by a licensee system engineer.
Immediate corrective action was accomplished when the damaged cell was replaced.
Further licensee investigation identified that the terminal had been identified as being loose almost a year earlier.
The craftsman who had identified the problem documented this finding in the comments section of a work package.
He did not verbally communicate the problem to his supervisor.
The supervisor's review of the work package overlooked the craftsman's comment.
The licensee also identified that the design of the battery equipment enclosure increased its susceptibility to terminal damage when work was being performed around the battery.
As further corrective actions, the craftsman and supervisor were counseled on the significance of the event and the need for a questioning attitude and thorough communications.
Meetings were also held with electrical shop personnel to emphasize the importance of thorough reviews of work packages, resolution of related work package comments, and the need to exercise caution when working within the HPCS battery enclosure.
In addition, a plant modification to improve the design of the HPCS battery enclosure was implemented during Refueling Outage R10.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequat.5 Closed LER 397 94-09 Revision 0:
" Incorrect Isolation Valve Com onent Selection" This LER involved the containment isolation provision for two containment monitoring systems.
As a result of a review initiated in response to Notice oF Violation 9402-02, the licensee identified that the sampling return lines for two containment monitoring systems had excess flow check valves installed as their inboard isolation valves.
The valves were declared inoperable because the containment leakage limit could have been exceeded in the event of a loss of coolant accident coincidence with the failure of the corresponding outboard containment isolation valve.
Immediate corrective action was accomplished by closing the outboard isolation valves and deenergizing the circuits that power their solenoid actuators.
The licensee replaced the excess flow check valves with 1-inch Anchor-Darling swing check valves.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequate.
11.6 Closed LER 397 94-13 Revision
1
& 2:
"Desi n Error in Electrical Circuitr for Containment Isolation" This LER identified a situation wherein the failure of a single electrical relay could prevent closure of the solenoid-operated containment isolation valves associated with the containment monitoring system (D) and the reactor recirculation (RRC) system hydraulic power units.
The cause was design errors during original construction.
Corrective actions involved a design review of control circuitry for all automatic solenoid actuated containment isolation valves to eliminate single failure vulnerability.
(The D was the first system identified as having a single failure vulnerability.
The RRC hydraulic power unit single failure vulnerability was identified by the licensee as a result of the corrective action described above.)
Modifications to.both systems were made to alter the control circuitry to eliminate the single failure vulnerability.
After completing the modifications, the licensee identified a deficiency in the design modification in that the modification involved Divisions 1 and
conduits which were routed in close proximity without providing adequate separation.
Continued operation was allowed despite the deficiency because compensatory actions, including a fire impa'irment and continuous manning of the area (in the control room) were implemented.
Permanent corrective actions are to provide siltemp flexible conduits for the Divisions 1 and 2 lines in order to attain adequate separation.
This was accomplished in Refueling Outage R10.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequat Il.7 Closed LER 397 94-16 Revision 0:
"Failure to Conduct Control Rod Maximum Scram Insertion Time Testin
"
The licensee's Technical Specification Surveillance Improvement Program identified that control rod scram time testing was required fo'llowing control rod drive system maintenance or modifications at
> 950 psig prior to entry into Operational Conditions I and 2.
However, the required testing had not been completed after previous refueling outages before entry into Operational Conditions I and 2.
Previous tests had been performed at
> 950 psig but prior to exceeding 40 percent power - i.e., after Operational Condition I had been entered.
The licensee concluded that the cause of the problem was nonconservative interpretation of the Technical Specification.
An emergency Technical Specification change request was submitted on July 8, 1994, requesting that scram time testing at
< 950 psig before entry into Operational Conditions I or 2 be allowed provided that the test is repeated at
> 950 psig prior to exceeding 40 percent reactor power.
The request was approved by the NRC on July 14, 1994.
Two training classes were, implemented in order to prevent.recurrence of nonconservative interpretation of the Technical Specifications, including related issues covered in Generic Letter 91-18.
The first class was given to licensed operators and Plant Operating Committee members.
The second class was given to the plant technical staff and engineering personnel.
The inspectors determined that the licensee's root cause assessment was adequate and verified that the corrective actions had been accomplished and were adequat ATTACHMENT 1
PERSONS CONTACTED Washin ton Public Power Su
S stem VS Parrish, Vice President Nuclear Operations
- J. Burn, Engineering Director
- G. Smith, guality Assurance Director
- P. Bemis, Regulatory and Industry Affairs Director R. Webring, Support Services Director
- J. Swailes, Plant General Manager
- G. Gelhaus, WNP-2 Projects Manager
- C. Schwarz, Operations Manager T. Love, Chemistry Manager
- S. Kirkendall, Assistant to the Technical Manager
- J. Albers, Radiation Protection Manager
- 0. Swank, Licensing Manager
- J. Huth, Plant Assessments Manager
- P. Inserra, guality Assurance Manager
- P. Taylor, Shift Manager G. Sanford, Planning, Scheduling, Outage Manager
- W. Haleievic, Operations Support Supervisor
- B. Hugo, Compliance Engineer
- H. Brant, Operations Consultant U.S. Nuclear Re ulator Commission
- H. Wong, Chief, Project Branch D
- 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 June 21, 1995.
EXIT MEETING An exit meeting was conducted on June 21, 1995.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee acknowledged the inspectors'indings.
The licensee identified that proprietary information was provided to and reviewed by the inspectors concerning the reactor water cleanup system chemical decontamination.
This inspection report contains no proprietary informatio ATTACHMENT 2 ACRONYNS AOT APRH BWR CO CRD CRO DG EDG FAO HP HPCS IZ(C IRB kw LOP HOP NW NRC PER ppH RHR RRC RVLIS RWCU SDC SGT SW TDAS WNP-2 WOT allowed outage time average power range monitor boiling water reactor clearance order control rod drive control room operator diesel generator emergency diesel generator followup assessment of operability health physics high pressure core spray instrument and control Incident Review Board kilowatt loss of power motor operated potentiometer megawatt U.S. Nuclear Regulatory Commission problem evaluation request plant procedures manual residual heat removal reactor recirculation reactor water level instrumentation reactor water cleanup shutdown cooling standby gas treatment service water transient data acquisition system Washington Nuclear Project
work order task
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