IR 05000338/1993030
| ML20029E824 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 02/17/1994 |
| From: | Belisle G, Garner L, Mcwhorter R, Taylor D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20029E818 | List: |
| References | |
| 50-338-93-30, 50-339-93-30, NUDOCS 9405230078 | |
| Download: ML20029E824 (18) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION g, ' - _
p *4 REGION 11
101 MARIETTA STREET, N.W., SUITE 2900 or
ATLANTA. GEORGIA 303234199
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Report Nos.:
50-338/93-30 and 50-339/93-30 Licensee:
Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.:
50-338 and 50-339 License Nos.:
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Facility Name:
North Anna 1 and 2 Inspection Conducted.
Dece r 19, 1993 - January 21, 1994 7/9#
Inspectors:
R. D. M9 idfte, Se ior Resident Inspector Date Signed ik Zl/7lff
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. R. Ta' lor,
- si nt Inspector Date Signed
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M.
. Garner, Project Engineer Dats Signed
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Approved by:
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~Date Signed G. A. Belisle, Sedtibn Chief Division of Reactor Projects SUMMARY Scope:
This routine resident inspection was conducted on site in the areas of plant status, operational safety verification, maintenance observation, surveillance observation, licensee event report followup, and action on previous inspection items.
Licensee backshift activities were inspected on December 21, 1993, and January 5, 6, 8, 12 and 13, 1994.
Resul ts:
Plant Operations functional area:
A strength was identified in operator transient plant control displayed during a rapid power reduction for a main feed pump repair and the subsequent power escalation (paragraph 3.d).
A' non-cited violation was identified for a failure to perform a calorimetric heat balance surveillance within the required time period (paragraph 6.c).
9405230070 940217 PDR ADOCK 05000338 G
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Maintenance functional area:
A strength was identified in secondary system material condition displayed-when few equipment problems resulted from a rapid power reduction for a main feed pump repair and the subsequent power escalation (paragraph 3.d).
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A violation was identified for a failure to perform American Society of Mechanical Engineers code-required bolting inspections for seven flanged joints where leakage was discovered dur,ing pressure te sting.
As a result, code relief and compensatory actions were required (paragraph 5.b).
Engineering functional area:
A weakness was identified due to a design change package being issued without a seismic and missile protection desian criteria review (paragraph 4.b).
Plant support functional area:
An unresolved item was opened to review final licensee investigation results
for an event concerning a locked high radiation area door (paragraph 3.c).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees L. Edmonds, Superintendent, Nuclear Training C. Funderburk, Superintendent, Outage and Planning J. Hayes, Superintendent of Operations D. Heacock, Superintendent, Station Engineering
- G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing
- W. Matthews, Assistant Station Manager, Operations and Maintenance q
- J. O'Hanlon, Vice President, Nuclear Operations D. Roberts, Supervisor, Station Nuclear Safety R. Saunders, Assistant Vice President, Nuclear Operations D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Maintenance
- J. Smith, Manager, Quality Assurance
- A. Stafford, Superintendent, Radiological Protection
- J. Stall, Assistant Station Manager, Nuclear Safety and Licensing Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Personnel
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- R. McWhorter, Senior Resident Inspector
- D. Taylor, Resident Inspector
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- G.
Belisle, Section Chief L. Garner, Project Engineer
- Attended exit interview on January 26, 1994.
- Attended exit interview on February 4, 1994.
Acronyms and initialisms used throughout this report are listed in the last paragraph.
j 2.
Plant Status Unit 1 operated at or near 100% power for the entire inspection period, Unit 2 operated at or near 100% power from the start of the inspection i
period until January 12, 1994.
On that date, a leak on the seal cooling line to Main Feed Pump C (2-FW-P-lC) required operators to expeditiously reduce power'to 50% in order to remove the pump from service.
The pump
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was repaired, and the unit returned to 100% power on January 13.
The unit continued to operate at or near 100% power for the remainder of the inspection period.
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3.
Operational Safety Verification (71707, 42700)
The inspectors conducted frequent control room tours to verify pruper staffing, operator attentiveness, and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain awareness of overall facility operations and reviewed operator logs to.
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verify operational safety and compliance with TS.
Instrumentation and safety system lineups were periodically revieed from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection program implementation, radiological work practices, plant security, and housekeeping.
DRs were reviewed to assure that potential safety concerns were properly reported and resolved.
a.
Licensee On-Site Organization Changes 1)
Effective January 1, 1994, the licensee reorganized the station Quality Assurance Department.
The new organization contained four groups which were assigned duties' to evaluate activities in four areas comparable to the NRC SALP evaluation areas (plant operations, maintenance, engineering and plant support).
Previous QA functions (audits, assessments and inspections) and personnel were assimilated into these four groups.
2)
On January 4, 1994, the licensee announced that Mr. C. Funderburk had been appointed to Superintendent, Outage and Planning.
He replaced Mr. R. Shears, who had been previously appointed to Superintendent, Maintenance.
b.
Deviation Report Reviews The inspectors reviewed the following DRs to assess their effects on plant' equipment and personnel:
1)
On January 3, 1994, DR 93-1955 documented a halon discharge-into the control room ventilation system.
The halon was inadvertently discharged while performing 1-PT-107.2, Fire Protection - Halon 1301 System:
Unit 1' Control Room, revision 16.
The inspectors reviewed the hazards presented to control room operhtors.
Loss prevention personnel weighed the halon bottle and estimated about 18 pounds had been discharged.
Based on the inspectors' UFSAR and
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facility Appendix R report review, the inspectors concluded'
that no personnel hazards were posed to control room operators from this small halon discharge.
The inspectors also reviewed the licensee's investigations into the event-cause and corrective actions.. A' procedure review revealed that 1-PT-107.2, step 6.2.10, stated,
" Remove the pilot line from the main halon bottle." An equipment walkdown' identified that the lines going to the
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halon bottles were not labeled.
The licensee concluded that the wrong pilot line was lifted due to poor labeling and a vague procedure. When the wrong pilot line was lifted, nitrogen was momentarily supplied to the halon bottle pilot valve which actuated the valve.
Contributing to this event was the electrician's failure to question the procedure and the as-found nitrogen line arrangement. As a result, the licensee indicated that the procedure would be clarified, the lines labeled, and electrical personnel instructed in the event.
Additionally, the licensee issued a staticr alert summarizing the event and encouraging personnel to question procedure and labeling problems prior to taking any actions.
The inspectors considered the corrective action taken by the licensee to be appropriate.
2)
On January 3, 1994, DR 93-1957 documented a situation discovered on December 30, 1993, when the inspectors identified that the pressure gauge for electrical penetration 2-PE-EP-23C read zero.
Discussions with the system engineer indicated that an "as-found" test could not be completed on this line due to a gross leak from a valve on the penetration leak monitoring line.
Leakage from these lines has been a problem in the past, and as a result, the copper lines on all electrical penetrations were being replaced as required by stainless steel lines.
The line for this penetration was replaced and a " Type B" leakage test successfully performed.
The inspectors verified that the penetration was restored, and that the containment pressure boundary had not been breached since the interior seal remained intact.
3)
On January 19, 1994, DR 94-57 documented a condition, discovered about 2:00 a.m. during operator rounds, where two of four RWST level transmitters were found to be reading erroneously.
The cause was postulated to be freezing due to low outdoor temperatures (approximately 2*F).
Tents with heaters were expeditiously placed around the transmitters, and the normal heat tracing circuits were verified to be operable.
By 3:00 a.m., the indications had returned to normal.
Additional corrective actions included energizing backup heat tracing circuits and placing tents and heaters around all RWST level transmitters for-both units. At the end of the inspection period, the licensee was evaluating why the correctly operating normal heat trace could not keep the lines from freezing and what long term corrective actions would be required.
The licensee evaluated the problem's significance and-concluded that the most limiting TS LCO for the condition was a 72-hour action requirement.
The inspectors verified the licensee's corrective actions, and independently
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reviewed the applicable TS.
The inspectors found no
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additional TS requirements other than those identified by the licensee.
Additionally, the inspectors reviewed the design basis for the transmitters as stated in the UFSAR.
Two of the four transmitters were required to provide an automatic safety injection swap-over to the containment sump
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during a design basis LOCA.
Since two transmitters' remained L
operable, the system would not have been prevented from performing its design safety function. The inspectors concluded that the licensee's actions were appropriate, c.
Unlocked High Radiation Area Door On January 12, 1994, the licensee identified a problem concerning a normally locked high radiation area door (number 14A).
The problem was discovered when a supervisor identified that a large area wipe survey had been performed, but a key had not been issued L
to the technician performing the survey.
The door was immediately verified locked, and an investigation was conducted into the problem's cause and consequences.
Based on employee interviews and a key control log review, the licensee concluded that the door was last verified locked when l
checked by an operator at about 9:00 p.m. on January 11.
At approximately 2:35 a.m. on January 12, when the supervisor noted l
the survey discrepancy, the door was inspected and found to be locked.
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When questioned about the survey discrepancy, the technician l
stated she entered the area without a key for'a routine large area
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wipe survey at about 10:45 p.m. on January 11. When passing.
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through the door, which was posted with a placard stating the door should be locked, the technician stated that although she reviewed i
the area radiation postings, she failed to note the unlocked door i
as unusual.
Upon survey activity completion, the technician i
l stated that the door slammed shut and appeared to latch upon exit.
The area was promptly surveyed, and it was confirmed that-radiation levels slightly exceeding 1000 mrem /hr existed near equipment in the area.
The highest radiation level areas were confirmed to be away from the immediate area surveyed by the
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technician. The licensee promptly reviewed dosimetry' records and :
found no excessive radiation exposures were-received by any L
individuals, including the survey technician.
A door latch inspection was performed, and a slight tendency to stick was noted and repaired. This was postulated to possibly
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prevent latching if the acor was softly closed, but it appeared that the mechanism worked properly _ if the door was allowed to slam shut on its automatic closer.
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At the end of the inspection period the licensee's investigations were continuing.
The inspectors will evaluate the licensee's L
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findings under Unresolved Item 50-338, 339/93-30-01, Evaluate Locked High Radiation Area Door Event.
d.
Main Feed Pump Seal Cooler Leak l
On January 12, 1994, operators were monitoring a leak on the cooling water lines for the Unit 2 Main Feed Pump C (2-FW-P-lC)
inboard seal. A third feed pump which normally could have replaced the pump was out-of-service for extensive maintenance.
At about 11:28 p.m.,
the leak increased to the point where shift supervision decided to promptly reduce unit power to allow
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removing the pump from service.
A power reduction was commenced, l
and at 1:36 a.m. on January 13, 50% power was reached and the pump was secured.
Repairs to the seal housing were commenced immediately.
The crack in the piping was found to be in the pipe nipple which attached the seal cooler piping to the pump seal housing.
The failure, in the threaded area, was most likely a fatigue failure due to vibration. The failed nipple was saved for further analysis. The seal cooler and the cracked pipe nipple were replaced, and the pump was returned to service. The inspectors observed portions of the maintenance activity.
The work was performed in a satisfactory manner with good supervisory oversight.
Both-QA and plant management were observed witnessing the maintenance activity.
At about 8:30 p.m. on January 13, the pump was successfully restarted, and a power increase was commenced.
The. inspectors observed the pump restart and power increase until approximately full power was reached at about 11:30 p.m.
The inspectors noted that operators controlled the power change well, and observed that very few equipment problems occurred in the secondary plant during both large power changes.
The inspectors judged that the licensee's performance during the event displayed strengths in operator transient plant control and secondary system material condition, e.
Major Station Modifications 1)
Station Blackout Diesel Installation Shortly after the fall 1993 Unit 2 refueling outage, the licensee began installing an additional diesel generator to comply with 10 CFR 50.63, Loss of All Alternating Current Power.
The inspectors routinely monitored the project's first phase which was diesel generator building construction. Additionally, the inspectors noted the diesel generating unit's arrival on-site.
The inspectors observed that the construction project appeared to be progressing well and that normal plant operations were unaffected except for a small fire protection header leak (paragraph 4.b).-
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Service Water System Restoration Project Also, shortly after the fall 1993 Unit 2 refueling outage, the licensee began work associated with SWSRP, Phase One, Stage Four.
This stage included extensive repairs to auxiliary service water lines from Lake Anna which provide a backup, non-safety water supply for the safety-related service water system.
Although non-safety in classification, the lines did provide support for the facility basis for meeting 10 CFR 50, Appendix R, fire protection requirements.
With preparations complete and a temporary GDC-2 exemption approved by the NRC, work to excavate and repair one auxiliary service water line commenced on January 4, 1994.
The inspectors routinely monitored the work and verified that Appendix R operability requirements for the remaining header were maintained and that normal safety-related equipment operation was unaffected by the work.
f.
NRC Notifications (93702)
1)
On December 24, 1993, the licensee notified the NRC as required by 10 CFR 50.72 concerning an emergency assessment capability loss.
The Unit 1 SPDS system failed at 12:20 a.m. which degraded the licensee's ability to use computer systems to assist with the plant status evaluation during an emergency.
Repairs were completed and the system was returned to servict at 6:10 a.m.
The inspectors reviewed the event and found the licensee's actions to be appropriate.
2)
On January 5, 1994, the licensee notified the NRC as required by 10 CFR 50.72 concerning an event that alone could have prevented the fulfillment of a safety function for systems needed to mitigate consequences of an accident.
For five minutes, two of three AFW pumps were degraded.
With the remaining motor driven AFW pump in its normal lineup to only one SG, a single fault on that SG with a loss of offsite power could have prevented the AFW system from operating.
This event occurred while the 2J EDG was out-of-service for scheduled maintenance which made the emergency power to the Unit 2 Train B motor driven AFW pump unavailable. While in this condition, a licensee engineer inadvertently caught his clothing on the trip lever for the turbine driven AFW pump and caused its overspeed trip mechanism to trip.
The trip was immediately detected by annunciation in the control room. The engineer contacted the control room, and an operator was dispatched to reset the trip mechanism. The total time that two pumps were degraded was five minutes.
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The inspectors reviewed the event, and verified that the a
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appropriate TS was entered and timely action was taken to restore the pump to an operable status.
No violations or deviations were identified.
One unresolved item was opened.
4.
Maintenance Observation (62703, 42700)
Station maintenance activities were observed and reviewed to verify that activities were conducted in accordance with TS, procedures, regulatory guides, and industry codes or standards.
a.
Auxiliary Feedwater Pump Maintenance On December 20, 1993, the inspectors observed maintenance on the Unit 2 turbine driven auxiliary feedwater pump (2-FW-P-2). The work was performed under WO 279216-01 and supplemental work instructions.
The maintenance was a continuing investigation to determine the reason for water intrusion in the pump's lube oil sump.
Oil samples had repeatedly indicated small water amounts, and previous maintenance efforts such as testing and replacing the oil cooler had failed to correct the condition.
The work involved draining the oil from the pump, flushing clean oil through the turbine bearings, and obtaining various oil samples before and during operation.
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Following the initial maintenance, the pump was run with oil
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samples taken every five minutes.
Slight increases in the oil's water content were noted for each successive sample. All samples were well below values previously determined not to affect the pump's ability to perform its safety function.
During the pump run, the inspectors and the licensee noted steam leakage from the governor throttle valve stem and apparent steam trap drain blockage.
Maintenance engineering indicated that the high humidity in the room may have caused condensation to get into the bearing housing and subsequently contaminate the oil.
The licensee formed a task team to investigate the problem. On January 17, 1994, the steam supply lines to the pump were placed in various configurations to troubleshoot the large steam quantities released into the pump room.
The licensee confirmed that several steam traps were leaking, and trap repairs were initiated. The pump was run again, and oil samples and temperature measurements were taken.
On January 19, the inspectors attended a meeting where the task team briefed licensee
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management on results and future plans.
At the end of the inspection period, the licensee was continuing to evaluate and plan further repairs.
This issue was previously reviewed by the inspectors and discussed in NRC Inspection Report Nos.
50-338, 339/93-18.
The inspectors found that the licensee knew about the problem since it was first reported on February 9, 1993, in DR 93-267.
The inspectors judged that the licensee's past
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efforts to resolve this problem were slow because alnost eleven months had elapsed from the initial problem identification.
However, in this inspection period, management directed increased efforts in resolving the problem.
The inspectors judged that the licensee's actions were now progressing at a more appropriate pace, b.
Fire Protection Header Leak On January 5, 1994, a backhoe working near the construction area for a new diesel generator building (paragraph 3.e.1)
inadvertently struck the indicator for fire protection header valve 1-FP-118, starting a leak from the valve bonnet.
Initial attempts by the licensee to isolate the header portion containing the valve were unsuccessful due to isolation valve leakage.
The licensee expanded the isolation boundaries to include ' additional valves, and isolated the leak on January 6.
The isolated fire header sections included the supplies to several outside hose stations and the Unit 2 Turbine Building deluge systems. The inspectors monitored licensee actions and verified that proper compensatory actions were taken for the degraded fire protection header.
Repairs were completed on January 7, and the system was returned to service.
The inspectors concluded that the licensee had taken appropriate actions in repairing the fire protection header ' leak.
After repairs were completed, the inspectors found that a seismic evaluation was performed to justify the return to service for the header portion exposed near 1-FP-118. The inspectors questioned if an evaluation was done prior to the leak to review the seismic and missile protection criteria for the piping which was exposed near 1-FP-ll8.
Licensee management reviewed the issue and confirmed that the work plan, DCP-92-010, should have, but did not take seismic and missile protection requirements into consideration for work done around the main fire protection header.
The licensee initiated DR 94-29 to document this condition.
The licensee's investigation results revealed that personnel preparing the DCP failed to realize the excavation magnitude required for the work and, as a result, did not identify that the header would possibly be exposed.
The inspectors considered this to be a weakness because the DCP was issued without a seismic and missile protection design criteria review.
c.
Charging Pump Inspections During the inspection period, the licensee removed charging pump 2-CH-P-1B from service for scheduled maintenance and internal component inspections. On January 5,1994, the internal inspectinns revealed nine defects on the clad inside the pump.
casing. The clad defects were of concern since they could allow acidic water to contact the casing carbon steel and challenge casing integrity due to corrosion.
Two defects were in the
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discharge nozzle area, and seven defects were in the suction area.
As a result of the defects, the licensee replaced the pump casing with a stainless steel casing.
These defects were similar in nature to defects found on pump 1-CH-P-lC in July 1993 and
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discussed in NRC Inspection Report Nos. 50-338, 339/93-20.
The licensee removed clad material in the defect areas and found the defects' sizes were too small to have an impact on pump operability. However, during clad material excavation r. ear the end of the pump housing, an additional circumferential crack was discovered.
This crack appeared to be a possible casing crack between the cylindrical portion of the casing and the eld plate area.
The licensee evaluated the new crack in detail te determine the effect on charging pump operability.
The licensee performed various non-destructive examinations on the area and discussed the problem with the pump vendor.
Preliminary conclusions indicated that the crack was not an actual casing crack as originally thought, but only an indication in the clad / casing interface. At the end of the inspection period, the licensee's evaluations were
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continuing. The inspectors assessed the licensee's actions and
agreed that pump operability did not appear to be affected.
Concerning the remaining charging pumps, pump 1-CH-P-1A was not i
affected by this defect mechanism because its casing was previously replaced with a stainless steel casing.
Pump 1-CH-P-1C was repaired as discussed above in July 1993.
The licensee completed inspections for pump 1-CH-P-1B in August 1993, and found no problems. At that time, the Unit 2 pump inspections were deferred due to a lack of parts for reassembly. At the end of the inspection period, the licensee planned to complete the remaining two Unit 2 pump inspections in sequence as soon as 2-CH-P-1B could be returned to service.
Since discoveries to date have not impacted charging pump operability, the inspectors considered the licensee's actionc to be appropriate.
No violations or deviations were identified.
5.
Surveillance Observation (61726, 42700)
i Station surveillance testing activities were observed and. reviewed to verify that testing was performed in accordance with procedures, test instrumentation was calibrated, LCOs were met, and any deficiencies identified were properly reviewed and resolved.
a.
Accumulator Isolation Valve Breaker Testing
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On December 30, 1993, the licensee provided the inspectors with a SNSOC approved memorandum concerning TS 3.5.1.
Specifically, the memorandum addressed a surveillance required on the Unit 2
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B accumulator discharge isolation valve, 2-SI-MOV-2865B. The surveillance involved an operability test on the motor operator supply breaker thermal overload protection device. To perform the
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test, the breaker handle was required to be unlocked and the breaker cubical opened.
TS 3.5.1 required that 2-SI-MOV-28658 be maintained open.
TS surveillance requirement 4.5.1.1.c required verifying that the breaker supplying power to the isolation valve operator was locked in the "off" position. _The memorandum proposed to have the secondary protection breaker for 2-SI-MOV-2865B tagged in the "off" position with an operator.
standing at the breaker to ensure the breaker was not closed for any reason.
The memorandum further stated that this proposed
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action met the TS 3.5.1 intent in that power to 2-SI-M0V-28658 was-to be administratively controlled to prevent valve motor energization.
SNSOC concurred that entry into the TS 3.5.1 action was not required as long as the above plan was followed.
The inspectors reviewed the memorandum and determined that the proposed actions would not meet verbatim TS requirements.
The inspectors expressed concern that TS required continuously maintaining control for power to the breaker using a lock and key.
After the inspectors concerns were raised with the licensee, the surveillance was delayed until TS compliance could be fully assured. On January 8, 1994, the licensee completed the
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surveillance by locking open the motor operator secondary J
protection breaker to meet the TS requirement.
During the surveillance, the inspectors verified the locking complied with TS 3.5.1.
b.
ASME Code Section XI Pressure Boundary Inspections On January 6,1994, the licensee informed the inspectors that a discrepancy had been discovered concerning ASME Section XI
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pressure boundary inspections conducted during the fall 1993
.j Unit 2 refueling outage.
Specifically, for twelve flanged joints which were noted to be leaking during pressure tests, a type VT-3 inspection with threaded fasteners removed had not been performed as required by the ASME Code Section XI, paragraph IWA-5250, 1986
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(A later review reduced the affected flange number to seven.) The licensee evaluated the situation and determined that'
a TS 4.4.10.1 surveillance requirement had not been fully complied
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with, and therefore entered TS Action Statement 4.0.3 at 10:00
a.m.
TS 4.0.3 allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for completing a missed surveillance prior to requiring entry into the applicable TS action statements.
The licensee additionally informed the inspectors that to perform
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the required inspections would require a plant shutdown, cooldown
and depressurization.
Furthermore, the licensee's work
documentation demonstrated that all but one joint had been-visually inspected with the threaded fasteners in place..The remaining joint _(the VCT tank manway cover)_cou.1d be monitored for leakage.
it was also noted that RCS leakage on Unit 2 had consistently been at or close to zero since the outage.
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these considerations, the licensee completed a safety evaluation and JCO, and requested relief from the code requirements.
q On January 6, 1994, a telephone conference was conducted between the licensee and NRC staff members at 11:00 p.m.
The licensee briefed the staff on the situation, and the JC0 results. The licensee proposed to take compensatory actions to:
(1) calculate
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RCS leakrate every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and immediately investigate any leakage greater than 0.4 gpm, (2) install a TV camera for remote VCT manway monitoring, (3) perform a calculation to determine how
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many fasteners were required to fail in order to cause a VCT i
catastrophic failure, and (4) perform the inspections at the next suitable outage.
The licensee provided a written request for code relief to the NRC on January 7.
The NRC verbally approved the request and the licensee exited TS action statement 4.0.3_at 9:57 a.m. on January 7.
The licensee reviewed this situation and concluded that the
problem developed for several reasons.
The individuals who performed the procedures were not familiar with code requirements, i
and thus failed to properly fill out work requests for the
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inspections as described in the procedures.
Additionally, the procedures. governing the inspections did not clearly delineate the
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need for an inspection with the fasteners removed.
The inspectors reviewed the procedures and agreed with the licensee's assessment.
To address these problems, the licensee planned to enhance the procedures and to increase the familiarity with the code requirements for personnel performing these procedures in the future.
The inspectors reviewed the requirements governing inservice
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inspection programs for the facility.
The inspectors found that 10 CFR 50.55a(g) and TS 3.4.10.1 required that ASME Code Class 1, 2 and 3 components be subject to inservice inspection requirements delineated in ASME Boiler and Pressure Vessel Code Section XI.
ASME Code Section XI, paragraph IWA-5250, 1986 Edition, required that leakage detected during inservice inspection pressure tests at bolted connections be evaluated by removing the bolting and performing a VT-3 type visual examination.
The licensee's failure to perform these inspections for all bolted connections resulted in code relief and compensatory actions.
This failure to perform code required inspections was identified as Violation 50-339/93-30-02, Failure to Remove and Inspect Threaded Fasteners.
One violation was identified.
6.
Licensee Event Report Followup (92700)
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The following LERs were reviewed and closed. The inspectors verified that reporting requirements had been met, causes had been identified, corrective actions appeared appropriate, and generic applicability had been considered.
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(Closed) LER 50-339/92-02:
Inadvertent ESF Actuation During CDA Functional Test This event concerned an inadvertent ESF actuation which occurred when an instrtaent air isolation valve was inadvertently shut during CDA functional testing.
The cause was a stuck valve auxiliary relay latch mechanism which prevented the auxiliary relay from returning to its normal state when the CDA reset push button was depressed.
The inspectors verified that licensee corrective actions to revise test procedures were complete. The procedure revisions required technicians to check all relays reset and manually reset relays which stuck prior to removing test jumpers.
Additionally, the licensee performed an evaluation to determine if latch mechanism operation could be improved.
The inspectors reviewed the licensee's evaluation results. The evalu tion was a
thorough in investigating additional corrective actions, and ruled out all actions other than large scale auxiliary relay replacement-or re-wiring large circuit segments. The licensee judged that these actions were not warranted, and that the procedural enhancements should be sufficient to prevent recurrence.
The
inspectors considered that the licensee's actions were adequate and noted that no similar problems were experienced with this test
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during the last two refueling outages.
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(Closed) LER 50-338/93-09:
Cold leg Safety Injection Line Flow Below Technical Specification Requirements Due to Overly Restrictive Acceptance Criteria
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This event concerned the failure for HHSI branch line flows to meet TS 4.5.2.h requirements during surveillance testing. The licensee concluded that the TS requirements for the flows were too restrictive and that known errors in the instrumentation used for the test made it extremely difficult to pass the test.
As corrective action, the licensee proposed a TS change to make the
TS requirements less restrictive.
These changes were later approved by the NRC.
Subsequently, this problem recurred on Unit 2 and was the subject of NRC Inspection Report Nos. 50-338, a
339/93-28 and a Notice Of Violation And Proposed Imposition Of Civil Penalty dated January 7,1994. The inspectors discussed concerns with plant management that corrective actions taken for the Unit 2 violation also address Unit 1, as applicable.
Additional Unit I corrective actions will be reviewed during closecut for the Unit 2 violation.
c.
Missed Calorimetric LERs (Closed) LER 50-339/92-09:
A Missed Surveillance On The
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(Closed) LER 50-338/93-18:
Missed Surveillance On The Performance Of The Calorimetric Heat Balance These LERs involved two examples of failure to perform a calorimetric heat balance within the TS prescribed frequency.
The first event on December 18, 1992, resulted from ineffective
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communication between an operator and his immediate supervisor.
The licensee's corrective actions included training on this incident with all operators to stress communications with supervisors. The inspectors verified that during LORP training cycle three in 1993, this event was discussed.
The inspectors i
reviewed the lesson plan and student handouts, and discussed with the instructor the material presented in the training session.
i The inspectors concluded that all corrective actions had been completed.
The second occurrence on October 16, 1993, was attributed to shift personnel becoming involved with other control room activities and not ensuring that the test was performed within its required time frame.
The inspectors confirmed that the two LERs had dissimilar root causes, and that the corrective action for the first event could not have reasonably been expected to prevent the later occurrence.
LER 50-338/93-18 identified that administrative actions were taken to prevent event recurrence, but did not specify what these actions were.
The inspectors determined that the primary action was to require that the normally daily calorimetric be performed twice daily (once per shift). The inspectors verified that this daily-required TS surveillance was being performed twice per day and that the Operations Routine PT And Work Schedule document had been revised to reflect this requirement. The inspectors concluded that this action should preclude repetition.
The failure to perform a TS required surveillance activity within the prescribed frequency was identified as violation 50-338/93-30-03, Calorimetric Heat Balance Not Performed At TS Frequency. This licensee identified violation is not being cited because criteria specified in Section VII.B of the NRC Enforcement Policy were satisfied.
d.
(Closed) LER 50-339/92-11:
Unit Entered Mode Three During Startup With One Steam Generator Level Channel In Trip Due To Personnel Error The LER reported a situation in which MODE 3 was entered with a SG 1evel channel in the tripped condition which was prohibited by TS.
Contributing to the event were an operator's failure'to consult-all applicable TSs and a difference between the Unit 1 and 2 TS MODE requirements for SG level instrumentation. The event was previously identified as NCV 50-339/92-13-01.
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The LER addressed two actions to prevent recurrence.
First, the event was to be discussed in LORP training during the second LORP cycle in 1993. The inspectors reviewed the lesson plan and discussed with the instructor the training provided concerning Unit I and 2 TS differences.
The inspectors determined that the training conducted should have provided licensed operators with a sufficient Unit 1 and Unit 2 TS difference knowledge to preclude recurrence.
The second corrective action was to submit a Unit 2 TS change so that the SG level instrumentation reouirements in Unit 2 TS would be consistent with those in the Unit 1 TS. This submittal was scheduled to be sent to the NRC in mid-1994.
Based upon the actions taken and those scheduled, the inspectors concluded that the licensee's corrective actions were adequate.
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e.
(Closed) LER 50-339/92-12:
Loss Of Power To 2H Emergency Bus During Undervoltage/ Degraded Voltage Testing The LER discussed a loss of power to the 2H emergency bus that
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occurred when electricians lifted a lead to isolate a relay during routine surveillance testing.
Lifting the lead should not have caused the event, and subsequent investigations into the event failed to determine a definite cause. During the event review, a
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test method using a strip chart recorder was identified that i
allowed the test to be performed without installing jumpers and
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lifting leads.
The licensee adopted this new method as corrective action to prevent recurrence.
The inspectors verified that 2-PT-36.llH, Degraded Voltage / Loss of Voltage Functional and ESF Response Time Test: 2H Bus, revision 4, was revised to utilize the new method.
Similarly, the current test procedures for emergency
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busses lH, IJ, and 2J were also verified to have been i
appropriately revised.
Additionally, the LER stated that during the next scheduled
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refueling outage, System Engineering would verify that the lead i
and termination points for the 2H undervoltage/ degraded voltage circuitry were in agreement with the station drawings. To address this item, System Engineering determined that proper component function and test light indication observations during 1993 outage testing provided similar verification to an as-built drawing verification. This was discussed with the cognizant engineer and the applicable drawing, No.12050-FE-2IT-22, was reviewed. The inspectors concurred for this specific case that the two methods provided equivalent confidence that the circuit was wired as shown on the drawing. The inspectors concluded the licensee's actions were adequate, f.
(Closed) LER 50-339/94-01:
Two of Three Auxiliary Feedwater Pumps Inoperable This LER concerned the event described in paragraph 3.f.2 where-two AFW pumps were rendered inoperable.
The event was precipitated when a licensee engineer inadvertently snagged his
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clothing on the trip lever for the turbine driven pump while performing an inspection. This tripped the turbine driven pump while one motor driven pump's emergency power supply was not available due to scheduled maintenance.
Corrective actions included an immediate return of the turbine driven pump to service, and counseling for the engineer concerning proper work practices around sensitive equipment.
The inspectors considered the licensee'e actions to be appropriate.
One non-cited violation was identified.
7.
Action on Previous Inspection Item (92702)
The following previous inspection item was reviewed and closed:
(Closed) VIO 50-338,339/92-03-02: Untimely Corrective Action for Potential RHR Overpressure Relief Inadequacy This violation concerned the licensee's failure to evaluate a safety concern identified by a Westinghouse bulletin until approximately two years after its receipt.
The bulletin identified a potential for RHR overpressurization due to possible inadequacies in relief valve l
capacities.
Immediate corrective actions for the concern involved temporary restrictions on RHR and AFW systems use which would prevent creating the conditions for an RHR system overpressurization.
The licensee originally intended to make these restrictions permanent through a TS
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amendment.
However, a final engineering analysis demonstrated that for the facility, the RHR overpressure concern was not applicable, and that'
the system could carry out its design safety functions.
The engineering analysis did recommend completing TS revisions concerning temperature o
requirements for LTOP system operability.
After analysis completion, l
associated LER 50-338, 339/92-03 was withdrawn.
The inspectors reviewed the engineering analysis and found it satisfactorily addressed the concerns.
Additionally, the inspectors verified that the TS revisions concerning LTOP system operability had been approved and issued as TS Amendments 170 and 149 for Units 1 and 2, respectively.
The main issue which was addressed by the violation was the timeliness for concern resolution. The licensee had originally received the bulletin from Westinghouse in February 1990, but'did not identify possible applicability to the facility until January 1992.
The licensee indicated that the cause for the delay was primarily attributable to a change in the engineering evaluation activity schedule which was made without full consideration for safety and operability concerns.
The licensee's 10ER program also failed to identify the significance for that delay.
The licensee's corrective actions for addressing timeliness involved.
upgrading Corporate Nuclear Safety's role both in reviewing initial industry event information, and in tracking all identified industry
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16-issues to full and timely resolution.
These changes were formalized by Revision 1, to VPAP-3002, Operating Experience Program.
The inspectors reviewed the revised procedures and verified the new responsibilities were clearly defined.
Additionally, the inspectors obtained a current status report for industry operating experience reviews and evaluated the timeliness for open items. The inspectors concluded that issues appeared to be properly tracked to resolution by the Corporate Nuclear Safety staff, and that the licensee's corrective actions had been i
properly implemented.
No violations or deviations were identified.
8.
Exit Interview The results were summarized on January 26 and February 4, 1994, with those persons identified in Paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection results addressed in the Summary section and those listed below.
Typg Item Number Status Descrintion URI 50-338,339/93-30-01 Open Evaluate Locked High Radiation Area Door Event (paragraph 3.c)
VIO 50-339/93-30-02 Open Failure To Remove And Inspect Threaded Fasteners (paragraph 5.b)
NCV 50-338/93-30-03 Closed Calorimetric Heat Balance Not Performed AT TS Frequency
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(paragraph 6.c)
VIO 50-338, 339/92-03-02 Closed Untimely Corrective Action For Potential RHR Overpressure Relief Inadequacy (paragraph 7)
LER 50-339/92-02 Closed Inadvertent ESF Actuation-l During CDA Functional Test (par agraph 6.a)
LER 50-339/92-09 Closed A Missed Surveillance On The Performance Of The Calorimetric Heat Balance Due -
To Personnel ' Error (paragraph 6.c)
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17 Type Item Number Status Description LER 50-339/92-11 Closed Unit Entered Mode Three During Startup With One Steam Generator Level Channel In Trip Due To Personnel Error (paragraph 6.d)
LER 50-339/92-12 Closed Loss Of Power To 2H Emergency Bus During Undervoltage/ Degraded Voltage Testing (paragraph 6 e)
LER 50-338/93-09 Closed Cold Leg Safety Injection Line Flow Below Technical Specification Requirements (paragraph 6.b)
LER 50-338/93-18 Closed Missed Surveillance On The
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Performance Of The Calorimetric Heat Balance (paragraph 6.c)
LER 50-339/94-01 Closed Two of Three Auxiliary Feedwater Pemps Inoperable (paragraph 6.f)
Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
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Acronyms and Initialisms AFW Auxiliary Feedwater ASME American Society of Mechanical Engineers CDA Containment Depressurization Actuation CFR Code of Federal Regulations DCP Design Change Package DR Deviation Report EDG Emergency Diesel Generator ESF Engineered Safety Feature GDC General Design Criteria GPM Gallons Per Minute HHSI High-Head' Safety Injection 10ER Industry Operating Experience Report JC0 Justification for Continued Operation LCO Limiting Condition for Operation LER Licensee Event Report LOCA Loss of Coolant ' Accident LORP Licensed Operator Requalification Program LTOP Low Temperature Overpressure Protection MOV Motor Operated Valve MREM /HR Millirem per Hour
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NCV Non-cited Violation NRC Nuclear Regulatory Commission QA Quality Assurance RCS Reactor Coolant System RHR Residual Heat Removal RWST Refueling Water Storage Tank SALP Systematic Assessment of Licensee Performance SG Steam Generator SNSOC Station Nuclear Safety and Operating Committee SPDS Safety Parameter Display System SWSRP Service Water System Restoration Project TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved Item VCT Volume Control Tank VIO Violation WO Work Order
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