IR 05000369/1998007
| ML20237B161 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 08/07/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20237B128 | List: |
| References | |
| 50-369-98-07, 50-369-98-7, 50-370-98-07, 50-370-98-7, NUDOCS 9808180076 | |
| Download: ML20237B161 (47) | |
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U.S. NUCLEAR REGULATORY COMMIRSION
REGION II
Docket Nos:
50-369. 50-370 License Nos:
50-369/98-07, 50-370/98-07 Licensee:
Duke Energy Corporation Facility:
McGuire Nuclear Station. Units 1 and 2 Location:
12700 Hagers Ferry Road Huntersville NC 28078 Dates:
May 31,1998 - July 11,1998 Inspectors:
S. Shaeffer. Senior Resident Inspector M. Sykes Resident Inspector M. Franovich, Resident Inspector N. Economos. Regional Inspector. Sections (M1.2, M1.3.
R. M o Regional Inspector (Sections E2.1. E4.1.
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E4.2. E4.3)
D. Forbes. Regional Inspector (Sections R1.1. R1.2.
.R2.1)
G. Wiseman, Regional Inspector (Sections F1.1. F1.2.
F2.1. F2.2, F5.1 F7.1 F8.1)
Approved by:
C. Ogle. Chief. Projects Branch 1 Division of Reactor Projects
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EXECUTIVE SUMMARY McGuire Nuclear Station. Units 1 and 2 NRC Inspection Report 50-369/98-07. 50-370/98-07 l-This integrated inspection included aspects of licensee operations.
maintenance, engineering and plant support. The report covered a six-week period of resident inspection.
In-addition, regional inspections were
performed in the areas of inservice inspection. Unit 1 outage modifications.
radiation controls and chemistry and fire protection.
Operations Operations oversight of Unit 1 outage related activities was excellent
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with few exceptions.-
(Section 01.1)
Operator res)onse to a loss of offsite power to the non-essential loads
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was good.
Tie impact on Unit 2 shared equipment, as a result of the loss of offsite power, was minimal.
Outage planning was effective in identifying risks and onsite power system alignments to minimize the impact of a loss of offsite power during planned busline maintenance.
(Section O'?.1)
The licensee's use of an event investigation team in response to a
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Unit I loss of offsite power was a prudent action.
However no definitive root causes for the current transformer failure and protective relaying actuation had been identified.
(Section 02.1)
The licensee's response to an earthquake which occurred near the
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McGuire Nuclear Station, was adecuate.
The licensee's response to the event was proactive in assuring cesign limits were not exceeded.
(Section 02.2)
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Unit 1 reactor building equipment was well maintained with no active
leaks identified prior to restart from.a scheduled refueling outage.
The pipe chase and lower ecuipment areas of the reactor building were free of loose materials anc equipment minimizing the potential for containment sump strainer blockage.
However. an unresolved item was identified to review the storage of divider barrier patch material for operability concerns.
Licensee containment material condition walkdowns were found to be effective with few problems noted.
(Section 02.3)
The licensee's response to increased Unit 1 unidentified reactor coolant
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system leakage during unit restart was in accordance with applicable Technical Specifications. Operator actions taken to address the problem were appropriate.
(Section 02 4)
An unp'lanned positive reactivity addition occurred on May 29. 1998.
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during removal of a main feedwater pump from service in preparation for Unit 1 shutdown and refueling outage.
Operations" immediate actions were appropriate.
Post-event reviews were considered good including self-assessment of operator performance and evaluation of potential equipment issues.
(Section 02.5)
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Three negative findings were identified during review of reactor coolant
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system draindown activities: u, the special pre-job briefing was not as detailed as previously observed midloop pre-job briefings: (2) the licensee planned. but did not perform, an unnecessary draindown to midloop: and (3) a weakness was identified for a procedure that was not correctly updated to reflect the new steam generators' spill over level.
(Section 04.1)
Maintenance Routine surveillance activities were completed satisfactorily.
(Section
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M1.1)
Inservice inspection examinations observed were performed in a
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satisfactory manner.
Nondestructive examination examiners were well trained and had good knowledge of plant components and applicable proceoural requirements. The licensee's evaluation and documentation of inspection results were consistent with applicable code requirements.
(Section M1.2)
A non-cited violation was identified regarding the licensee's failure to
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include in the weld count all the welds in the emergency core cooling system as required by American Society of Mechanical Engineers Code Section XI.
(Section M1.2)
An ultrasonic examination verified that weld defects in part length
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control rod drive pressure housings identified at Prairie Island were not present at McGuire Unit 1.
The examination was performed with a qualified procedure.
Personnel were well trained and the licensee provided adequate oversight during the activity.
The examination was consistent with applicable procedural requirements.
(Section M1.3)
A non-cited violation was identified for failing to perform a Technical
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Specification required surveillance on the Unit I refueling bridge auxiliary hoist.
(Section M4.1)
A non-cited violation was identified for not providing sufficient
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procedural guidance for assembly of a Unit 1 main feedwater/ containment isolation valve actuator.
Current testing-may not be effective in identifying actuator performance issues.
(Section M4.2)
The licensee's evaluation of the protective coating used on the
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refueling water storage tank interior surfaces and the calculations performed to determine acceptance criteria for operability were satisfactory.
(Section M8.1)
Enaineerina l
The overall licensee response to each of the emergency diesel generator
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sub-component failures was good in,that appropriate investigations and l
subsequent actions were performed to assure the reliability of the j
generators.
(Section E2.1)
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Fuel inspection activities were good and confirmed a suspected leaking
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fuel rod in thrice burned fuel. A non-cited violation was identified for a spent fuel pool configuration management issue involving a burnable poison assembly located in a spent fuel pool location which was thought to be em]ty.
Fuel reliability at McGuire continued to be very good.
(Section E2.2)
Root cause investigation of emergency diesel generator sub-component
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failures was thorough and aggressive.
(Section E4.1)
A violation was identified for inadequate oversight of contractor
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activities for the rebuild of the emergency diesel generator cylinder heads.
(Section E4.1)
The small engineering backlog indicated that appropriate resources and
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management attention were focused on completing engineering activities.
(Section E4.2)
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10 CFR 50.59 safety evaluations for Unit 1 outage modifications were
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comprehensive and well detailed.
(Section E4.3)
A non-cited violation was identified for inadequate work instructions
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which implemented the refueling water storage tank modification that l
inadvertently removed a Technical Specification required instrument from
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service.
(Section E4.3)
An operations Performance weakness was identified for inadecuate l
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awareness of slutdown plant conditions.
Operations approvec the tagout of the established shutdown boron injection flow path without verifying l
the availability of an alternate flow path.
(Section E4.3)
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Plant Supoort
The licensee met 10 CFR 20 requirements for control of personnel
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l monitoring control of radioactive material. radiological postings,
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radiation area,. and high radiation areas.
(Section R1.1)
The licensee was maintaining programs for controlling exposures as low
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as reasonably achievable and continued to be effective in controlling overall collective dose.
All personnel radiation exposures to date in 1998 were below regulatory limits.
(Section R1.2)
A violation was identified for failure to establish procedural guidance
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for degassing the Unit 1 volume control tank. This resulted in an unplanned, but monitored release to the environment.
(Section R1.2)
The respiratory protection program was being implemented as required by
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10 CFR Part 20 Subpart H.
Survey instrumentation had been adequately maintained.
(Section R2.1)
During 1997 and 1998 there were tw6 incidents of fire within safety
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significant plant areas. When fires occurred. licensee personnel
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contained the fire to the original source. and gevented the fire from
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spreading to other equipment or cables.
(Section F1.1)
The implementation of procedural requirements for using and storing
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transient combustibles in safety-related areas was good. The material condition in the plant indicated that the various plant departments were properly implementing their responsibilities for combustible material control.
(Section F1.2)
The observed level of plant housekeeping reflected good organization and
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cleanliness practices on the part of plant workers.
(Section F1.2)
A fire protection inspection and surveillance testing program weakness
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was identified for not having procedural guidance to verify the RCP oil col',ection system tank fluid level.
Plant uperators had sufficient procedural guidance to identify an oil leak from the reactor coolant pump oil lubrication system of any one of the RCP motors and take appropriate action.
(Section F2.1)
The fire barrier penetration seals were functional.
However, the
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licensee did not satisfy the guidance of Generic Letter 86-10 for engineering evaluation documentation that evaluated the adequacy of the deviations from a tested fire barrier configuration.
The licensee had implemented a.nroject to inspect, revalidate the installation of penetration seals. and provide documentation to identify the design specification and bounding test criteria applicable to each fire barrier penetration.
(Section F2.21 The fire brigade organiza1 o a.id drill program met the requirements of
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the site procedures.
The pe,,ormance by the fire brigade as documented by the licensee's c' rill evaluations was good.
(Section F5.1)
The 1998 Triennial Fire Protection Audit of the facility's fire
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protection program was comprehensive and effective in identifying fire protection program performance to plant management.
(Section F7.1)
The fire protection maintenance inspection and periodic test program was
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sufficient to verify operability of the auxiliary building fire protection water system.
(Section F8.1)
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Report Details Summarv of Plant Status Unit 1 Unit 1 began the inspection period in Mode 5. for the cycle 12 refueling outage.
During the period, the core was off loaded and reloaded. in conjunction with many other outage activities as discussed in this report.
The unit was restarted on July 1, 1998, and reached approximately 100 percent power on July 8, 1998.
The delay in reaching 100 percent power was attributed to completion of modifications to the main feedwater isolation valves. On July 11. 1998. unit power was reduced to 95 percent to repair a failed actuator stem on main turbine throttle valve number 1.
Unit 2 Unit 2 operated at approximately 100 percent power throughout the inspection period.
I. Operationc
Conduct of Operations 01.1 General Commenis (71707)
Using Inspection Procedure 71707 the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious.
Operations oversight of Unit 1 outage related activities was excellent with few exceptions.
Saecific events and noteworthy observations are detailed in the sections w1ich follow.
01.2 Ooerations Clearances (71707)
The inspectors reviewed a variety of clearances during the inspection period, including standardized system block tagouts used to remove and restore key safety-related systems to support the Unit 1 outage. The inspectors observed that the sampled clearances were pro)erly prepared and authorized, and that the tagged components were in t1e required positions with the a noted in this area. ppropriate tags in place.
No specific problems were 01.3 10 CFR 50.72 Notifications a.
Insnection Scoce (71707)
During' the inspection period, the licensee made three notifications to the NRC.
The inspectors reviewed the events associated with each notification for impact on the operational status of the facility and equipment.
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b.
Observations and Findinqs On June 3. 1998, the licensee made a report to the NRC in e
accordance with the requirements of 50.72 regarding a Unit 1 main feedwater isolation valve which had been previously installed with the accumulator internals incorrectly oriented. This issue is discussed in Section M4.2.
On June 3. 1998, the licensee made a report to the NRC in
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accordance with the requirements of 50.72 regarding a valve seat failure on the 2A emergency diesel generator. This issue is discussed in Sections E2.1 and E4.1.
On June 3,1998, at approximately 3:52 p.m., the licensee made a
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report to the NRC in accordance with the requirement of 10 CFR 50.72 regarding a declaration of a Notification of Unusual Event (NOUE) emergency class condition. The NOUE was due to a loss of offsite power event on Unit 1.
This event is further discussed in Section 02.1.
Operational Status of Facilities and Equipment 02.1 Unit 1 Loss of Offsite Power (LOOP)
a, Insoection Scooe (71707. 40500)
The inspectors responded to a June 3,1998. Unit 1 LOOP to evaluate licensee recovery activities and plant response.
b.
Observations and Findinas The inspectors responded to the control room to observe operator performance and associated activities following the Unit 1 LOOP event.
At 3:33 pm on June 3. 1998, with Unit 1 in Mode 5 and the 1A main busline de-energized for pre-planned maintenance power was lost to the IB main busline.
The loss of both Unit 1 main buslines resulted in a loss of power to the Unit I non-essential load centers and shared load centers )owered from Unit 1.
The licensee made a Notification Of Unusual Event (NOUE) at 3:52 pm due to a loss of offsite power in Modes 1-6 in accordance with station arocedure RP/0/A/5700/00. Classification of Emergency. At the time of tie event, the Unit 1 essential loads were being supplied from Unit 2 through the shared standby transformers SATA E
and SATB.
No undervoltage conditions occurred on the Unit 14160V essential buses and no emergency diesel generator automatic starts were required. The licensee restored power to the IB busline at 4:12 pm and terminated the NOUE at 4:44 pm on June 3, 1998.
McGuire Unit 2 was operating at 100 percent power when the Unit 1 LOOP occurred. The loss of power to the shared loads affected the instrument air system and the digital rod position indication (DRPI).
DRPI was rendered inoperable for approximately 5 minutes.
The inspectors L
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determined that following the loss of DRPI the operators used other control room indications and evaluated available plant parameters to determine control rod pos.ition.
The loss of instrument air resulted in closure of the Unit 2 moisture separator reheater second stage control valves causing an increase in main steam pressure and resultant increases in reactor coolarit system (RCS) average temperature (Tavg).
The rod control system functioned as expected returning Tavg to specified program parameters.
The licensee stabilized instrument air system pressure by starting a standby instrument air compressor and restored the reheater control valves to the normal position preventing additional operational transients on Unit 2.
The inspectors determined that the licensee had adequate staffing to cope with the Unit 1 LOOP and assure continued safe operation of Unit 2.
The inspectors monitored Unit 1 RCS temperature and evaluated Unit 2 operating plant parameters.
The inspectors also evaluated the offsite and onsite power system configuration.
The licensee had realigned the Unit 1 essential buses during the outage to minimize the potential risk of a LOOP during main busline maintenance.
The inspectors noted that this power system realignment to minimize potential impact of a LOOP was prudent and a good example of outage risk management.
The licensee assembled an event investigation team (EIT) to perform a systematic investigation of the event.
The team concluded that a fault had occurred in the Unit 1 230 kV switchyard initiating the actuation of several protective relays. The fault damaged the X-phase current transformer for power circuit breaker (PCB) 12 and caused protective relaying to isolate the damaged component.
This automatic isolation.
coupled with other unexpected relay actuations, resulted in a loss of power to the 1B main busline.
At the end of the inspection period the licensee was performing additional evaluations to determine why the unexpected relays actuated.
Pending further NRC review of the licensee efforts to determine why unexpected relays actuated is identified as Inspector Followu] Item (IFI) 50-369,370/98-07-01. Unexpected Relay Actuation During Unit 1 LOOP.
c.
Conclusions Operator res)onse to a loss of offsite power to the non-essential loads was good.
T1e impact on Unit 2 shared equipment, as a result of the loss of offsite power. was minimal.
Outage planning was effective in identifying risks and onsite power system alignments to minimize the impact.of a loss of offsite power during planned busline maintenance.
The inspectors noted that the licensee's use of an EIT was a prudent action.
However, no definitive root causes for the current transformer failure and protective relaying actuation had been identified at the end of the inspection period. An inspector followup item was identified to
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review the licensee's efforts to determine why unexpected relays actuated.
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02.? Resoonse to Earthouake Identified Within 15 Miles of McGuire Nuclear Station a.
Insoection Scope (71707)
The inspectors reviewed the potential im]act to the site from an earthquake detected in the vicinity of t1e plant.
The inspectors discussed the event with on duty personnel and reviewed the licensee's seismic monitoring capability and assessed system operability.
b.
Observations and Findinas On June 4.1998, local area seismic monitoring detected an earthquake around Mooresville. North Carolina. which is approximately 14 miles from the McGuire Nuclear Station.
The earth magnitude of 3.2 on the Richter scale. quake was estimated as a The inspectors interviewed personnel on duty during the time of the earthquake and determined that no physical activity related to the earthquake was noted by the individuals.
Furthermore, no seismic monitoring instrumentation at the plant recorded shocks associated with the earthquake and no seismic monitoring instrumentation alarmed in the control room.
Due to the earthquake proximity. the licensee performed additional reviews of the onsite seismic monitoring instrumentation and verified no equipment problems with the seismic monitoring instrumentation.
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Conclusions The inspector concluded that the licensee's response to an earthquake, which occurred near the McGuire Nuclear Station, was adequate.
The inspectors also concluded that the licensee's response to the event was proactive in assuring design limits were not exceeded.
02.3 Full Temperature and Pressure Insoection of Reactor Buildina and Eauipment a.
Inspection Scone (71707. 62707. 71750. 37551)
During Mode 3. the inspectors conducted inspections of the Unit 1 reactor building and ecuipment to verify that accessible portions of selected safety relatec systems and components were properly aligned and the areas were free of loose materials that could potentially impact plant operations during the recirculation phase of core cooling.
b.
Observations and Findinas On June 30. 1998, the inspectors performed observations of the reactor building and equipment to verify leak tightness and containment cleanliness.
The inspectors focused on areas and components near completed outage maintenance work activities.
The inspectors also confirmed Appendix R required reactor coolant Jump oil collection containers were empty and properly' aligned.
T1e inspectors also
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verified that fire suppression equipment removed during reactor coolant pump motor ID replacement had been reinstalled.
The inspectors identified several rubber containment wall divider barrier replacement patches that, although secured. could potentially degrade emergency core cooling system (ECCS) operation during the recirculation phase. The ins)ectors presented this concern to the licensee to determine 4f the Jarriers had been incorporated into the sump blockage evaluations performed to ensure operability of emergency core cooling systems. The licensee stated that the material had intentionally been left in the containment area; however, plant drawings had not been updated to reflect the material.
Pending further review of the impact of this material remaining in the containment on sump performance. this is identified as Unresolved Item (URI) 50-369/98-07-02 Divider Barrier Patches Left in Containment Building Following Outage.
The inspectors noted that four lower ice condenser inlet doors between I
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the A steam generator and pressurizer had moisture accumulations at the base of the inlet doors.
The moisture was determined to be condensation resulting from elevated reactor building humidity. The inspectors presented these observations to licensee engineering for review.
The licensee stated that the moisture was expected due to humidity levels in the containment and did not affect ice condenser system operability.
The inspectors noted that reactor building equipment and support systems were properly maintained and aligned. The inspectors also evaluated incore instrumentation rooms for pressure boundary leakage, cleanliness, and equipment condition.
No problems were noted in these areas.
During inspections of the u]per containment areas, the inspectors identified an electrical ca]le tray beneath a containment penetration supplying glycol to the ice condenser system which had noticeable corrosion and evidence of glycol leakage on approximately six feet of the cable run.
The cables were located in upper containment adjacent to the hydrogen recombiners.
Although the affected cables were determined by the licensee to be non-safety related, the inspectors were concerned about potential electrical shorting which could lead to a fire or other equipment malfunction.
The licensee took actions to remove the residual
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glycol from the tray and evaluated the condition of the cable. The
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licensee determined that the cable was not seriously damaged.
PIP 1-M98-2346 was identified to address long term corrective actions for the degraded condition.
The inspectors considered the licensee's immediate l
corrective action acceptable: however, the inspectors noted that the licensee's final containment closeout inspections did not identify this condition.
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Conclusions l
The inspectors concluded that reactor building equiament was well
maintained with no active leaks identified.
With t1e exception of the divider barrier seal patches, the inspectors confirmed that the pipe
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verified that fire suppression equipment removed during reactor coolant pump motor ID replacement had been reinstalled.
The inspectors identified several rubber containment wall divider barrier replacement patches that, although secured, could potentially
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degrade emergency core cooling system (ECCS) operation during the recirculation phase.
The ins)ectors presented this concern to the q
licensee to determine if the Jarriers had been incor orated into the
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sump blockage evaluations performed to ensure operab lity of emergency core cooling systems.
The licensee stated that the material had intentionally been left in the containment area; however, plant drawings had not been updated to reflect the material.
Pending further review of the impact of this material remaining in the containment on sump
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performance. this is identified as Unresolved Item (URI) 50-369/98-07-
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02. Divider Barrier Patches Left in Containment Building Following Outage.
The inspectors noted that four lower ice condenser inlet doors between the A steam generator and pressurizer had moisture accumulations at the base of the inlet doors.
The moisture was determined to be condensation resulting from elevated reactor building humidity. The inspectors presented these observations to licensee engineering for review. The licensee stated that the moisture was expected due to humidity levels in the containment and did not affect ice condenser system operability.
The inspectors noted that reactor building equipment and support systems were properly maintained and aligned. The inspectors also evaluated incore instrumentation rooms for pressure boundary leakage, cleanliness, and equipment condition.
No problems were noted in these areas.
During inspections of the upper containment areas, the inspectors identified an electrical ca)le tray beneath a containment penetration supplying glycol to the ice condenser system which had noticeable corrosion and evidence of glycol leakage on approximately six feet of the cable run. The cables were located in upper containment adjacent to the hydrogen recombiners.
Although the affected cables were determined by the licensee to be non-safety related. the inspectors were concerned about potential electrical shorting which could lead to a fire or other equipment malfunction.
The licensee took actions to remove the residual olycol from the tray and evaluated the condition of the cable. The licensee determined that the cable was not seriously damaged.
PIP 1-M98-2346 was identified to address long term corrective actions for the degraded condition.
The inspectors considered the licensee's immediate corrective action acceptable; however, the inspectors noted that the licensee's final containment closecut inspections did not identify this condition.
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Conclusions
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The inspectors concluded that reactor building equiament was well l
f maintained with no active leaks id5ntified. With t1e exception of the
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divider barrier seal patches, the inspectors confirmed that the pipe
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chase and lower equipment areas of the reactor building were free of loose materials and equipment which minimized the potential for containment sump strainer blockage.
The inspectors identified a URI to review the storage of patch material for operability concerns.
Licensee containment material condition walkdowns were found to be effective with few problems noted.
02.4 Unidentified Leakaae Greater Than One Gallon oer Minute (com)
a.
Insoection Scope (71707)
During the restart of Unit 1 on June 30, 1998, the inspectors reviewed the licensee's response to an increased leakage rate w1ich briefly exceeded the Technical Specification (TS) limit.
b.
Observations and Findinas With Unit 1 in Mode 3 preparing to enter Mode 2. a reactor coolant system leakage verification revealed an unidentified leakage rate of 1.2 gam, which exceeded the TS allowable leakage limit of 1.0 gpm.
It 51ould be noted that this was the first RCS leakage calculation since the unit reached full operating temperature and pressure. Operators stopped the startup process and entered the action of TS 3.4.6.2.. which required that the leakage be reduced to within allowable limits within four hours or the unit was to be placed in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Leak searches did not identify any obvious external leak: however. various valves were adjusted for stem or other potential leakage.
After approximately two hours, a second leak rate was performed and the unidentified leakage was approximately 0.6 gpm.
The inspectors monitored the licensee's response to the abnormal leakage and verified that the existing conditions did not recuire entry into any emergency procedures.
No plant cooldown was requirec.
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Conclusions
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The licensee's response to increased Unit 1 unidentified reactor coolant system leakage during unit restart was in accordance with applicable Technical Specifications. Operator actions taken to address the problem were appropriate.
02.5 Unit 1 Reactivity Event Involvina Main Feedwater (MFW) Pumo Ooeration a.
Insoettion Scoce (71707)
The inspectors reviewed the conditions related to a reactivity event that occurred during removal of a main feedwater pump from service.
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operational self-assessment of the event and corrective actions were l
also reviewed. The inspectors also reviewed procedures for feedwater pump removal from service and the licensee's corresponding operator training materials for feedwater pump speed control.
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b.
Observations and Finoinas On May 29, 1998, at approximately 40 percent reactor power. operators were removing the IB MFW pump from service during unit shutdown for the 1E0C12 refueling outage.
A low level alarm for the D steam generator (SG) annunciated and an operator took manual control of the A MFW pump in an attempt to increase level.
Consequently, the SGs were overfilled and an RCS cooldown of a] proximately 3 cegrees occurred.
This resulted in a temperature mismatc1 between Tavg and Tref which caused the rod control system to respond by stepping out control rods. The net effect was an increase of 3 to 5 percent in reactor power.
i The licensee performed a comprehensive self-assessment to determine the
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facts and evaluate potential operator and ecuipment performance problems.
Operator issues identified incluced pre-job briefing cuality, operator performance. procedure adequacy. simulator fidelity, anc the impact of trainees in the control room.
Speed controller problems were not a contributing factor to this reactivity excursion per engineering evaluation.
Procedural enhancements were made to provide appropriate guidance to operators on the sensitivity of the new SG to feedwater
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c.
Conclusions An unplanned positive reactivity addition occurred on May 29. 1998.
during removal of a main feedwater pump from service in preparation for
Unit 1 shutdown and refueling outage.
Operations' immediate actions were appropriate.
Post-event reviews were considered conti including self-assessment of operator performance and evaluation of potential equipment issues.
Operator Knowledge and Performance 04.1 Unit 1 RCS Draindown and Reduced Inventory Doerations a.
Insoection Scooe (71707)
The inspectors observed a special pre-job briefing and control room
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activities associated with draining of the RCS. The inspectors verified I
that these evolutions were performed in accordance with a) proved procedures, that appropriate oversight was present, and tlat TS requirements were followed.
b.
Observations and Findings j
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A post-refueling draindown to reduced RCS level was performed on June 20. 1998. The licensee drained RCS level from approximately 375 inches above centerline of the RCS hot lea to 16 inches to remove nozzle dams and install the reactor vessel head.
Reduced inventory is approximately 48 inches above centerline (3 feet below the reactor vessel flange).
Midloop conditions at McGuire is 15 inches or iess above centerline.
The draindown of the RCS was performed in accordance
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with operating procedures (OP) OP/1/A/6100/S0-3. Draining the Refueling I
Cavity, ano OP/1/A/6100/SU-2, RefueUng and Replacing the Reactor Vessel I
Head.
Unit 1 operated approximately 73 hours8.449074e-4 days <br />0.0203 hours <br />1.207011e-4 weeks <br />2.77765e-5 months <br /> in reduced inventory.
Prior to the dr3indown evolution, the licensee conducted a special pre-job briefing as required by procedures for conduct of infrequently performed evolutions.
The inspectors observed that the pre-job briefing was adequate: however, it was not as detailed as pre-job briefings the inspectors had witnessed in 1997 to support midloop operations during a Unit 2 forced outage. Although good egnasis was placed on operators not keying in on one RCS level parameter alone (based on industry shutdown experience), there was no discussion on maximum allowable deviation among level instruments. Additionally. the desired RCS draindown level was noted several times as approximately 12 inches above centerline (midloop operations).
An RCS refili event that cccurred during no-mode conditions during the outage was briefly mentioned:
l however, the discussion did not clearly describe that the event related to a mispositioned RCS level instrument valve for the same wide range indication the operators would be using.
A procedurally required maximum 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit in midloop operations (with the head in place) was not flagged in the pre-job brief and was discovered while draining the RCS (discussed below).
During the attempted draindown to midloop, operators encountered a procedural restriction that would prevent entry into midloop conditions.
On page 6 of OP/1/A/6100/SU-2. the control room SR0 was to verify that the RLS will be refilled to exit midloop within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, following setting of the vessel head (which was required to be done within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of entering midloop). A limit and precaution for the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time-limit was also noted in front of the procedure.
The basis for this step was related to thermocouple availability and an industry commitment (as noted in the limits and precautions).
The outage schedule did not support this step since midloop was scheduled for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in order to complete steam generator (SG) eddy current inspection activities.
The draindown continued while the licensee attempted to resolve the procedure / schedule issue. The draindown was stopped at 16 inches because of this restriction.
Following this scheduler and procedural conflict, the licensee recognized that draindown to midloop was not necessary in order to remove nozzle dams. The newly instai ed Babcock and Wilcox International (BWI) steam generators differed f rom the previous Westinghouse steam generators and made entry into midloop l
unnecessary to remove nozzle dams. Operations personnel did not realize thic prior to the draindown. The inspectors noted that an unnecessary
,
entry to midloop and subsequent reduced margin of safety would have j
occurred had the outage schedule allowed operators to proceed through
'
the subject step in the draindown procedure.
During reduced inventory operations, the inspectors questioned operations personnel if the RCS level diagram provided in OP/1/A/6100/SD-20. Draining the RCS (shutdown), were correct. A copy of the 50-20 diagram was opened in the control room and being referenced by l
operators during the draindown.
The inspectors noted that Procedure
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9 OP/1/A/6100/SU-2 did not provide a RCS level diagram.
The inspectors
)
noted that the OP/1/A/6100/SD-20 diagram indicated that the SG manway spillover level was 16 inches as opposed to the new SG value of approximately 28 inches.
In response, the licensee investigated this and found that a math error was made during an update of the procedure.
Human error appeared to be the root cause.
The inspectors considered this procedure inaccuracy a weakness. The licensee's immediate corrective actions included a review of operating procedures that may have been impacted by this type of error.
Inspectors verified that OP/1/A/6100/SU-5, Refilling the RCS in the control room contained the j
correct diagram prior to RCS refill.
c.
Conclusions
i Three negative findings were identified during the inspectors' review of RCS draindown activities: (1) the special pre-job briefing was not as thorough as previously observed midloop pre-job briefings: (2) the licensee planned, but did not perform, an unnecessary draindown to midloop: and (3) a weakness was identified for a procedure that was not correctly updated to reflect the new steam generators' spill over level.
Overall, observed activities were adequately performed.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scoce (611256_, 62707)
The inspectors observed portions of the following work activities:
Procedure / Work Order Title PT/2/A/4350/002A 2A EDG Operability Run PT/2/B/4350/002B 2B EDG Operability Run PT/2/A/4450/003B Unit 2 Train B Annulus Ventilation System Operability Test b.
QDservations and Findings
,
The inspectors witnessed the above surveillance and other selected l
surveillance-be.s to verify that approved procedures were available and l.
in use; tE.. t.pment was Calibrated: test prerequisites were met:
l system restoicrion was completed: and acceptance criteria were met.
In i
addition. the inspectors reviewed or witnessed routine maintenance
)
activities to verify, where applicable, that approved procedures were available and in use, prerequisites. were mete equipment restoration was completed, and maintenance results were adequate.
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_ _,. _ -. _, _, _.. _ _ _. - - _ _. _. - _ - _ _ _ _ _ _ _ _ _ _ _ _. _. _ _. _,,. - - - _.. _ _ _, - _ _ - -.,, _ _. _. - - -. _ _,, _ _ _ _ _
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c.
Conclusions Routine surveillance activities and maintenance activities observed were completed satisfactorily.
M1.2 Jnservice Insoection (ISI) Unit 1 a.
Jnsoection Scoce (73753. 73052. 73051)
This was the twelfth refueling outage for this unit, which was the last outage of the second period of the second 10-year interval.
The
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inspectors observed in-process examinations. reviewed procedures and records indicated below. to determine whether ISI examinations were I
being conducted in accordance with the applicable codes, procedures, regulatory requirements and licensee commitments. The applicable code for ISI activities was the American Society of Mechanical Engineers
(ASME) Boiler and Pressure Vessel (B&PV) Code.Section XI,1989 Edition (Code).
The licensee's technical support group was in charge of ISI examinations.
b.
Observations and Findinas
.
)
Review of Nondestructive Examination (NDE) Procedures (73052)
The inspector reviewed the procedures listed below to determine whether they were consistent with applicable code requirements and regulatory commitments. The procedures were also reviewed in the areas of procedure approval, requirements for qualification of NDE personnel.
I visual acuity and compilation of required records.
NDE-900. Rev. O Ultrasonic Examination of Reactor Coolant Pump Flywheels NDE-35. Rev. 17 Liquid Penetrant Examination j
Observation of Work Activities (73753)
)
The inspector observed work activities, reviewed certification records for NDE equipment and materials, and reviewed qualifications for personnel utilized for ISI examinations observed. The observations and reviews conducted by the ir.spector are documented below.
I
.Ltm Component Exam-Comments G01.001.002 RC Pump Ultrasonic No l
Flywheel RCP-1B Recordable
,
i Indications (NRI)
j
B09.040.113 Pipe to Valve L.iquid Penetrant Class A Stress
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Weld. NRI
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809.040.115 Pipe to Valve Liquid Penetrant Class A Stress Weld. NRI Review of ISLPrgaram (73051)
By review of the licensee's Problem Investigation Process (PIP) re] ort 0-M97-3386 drawings, related documents and through discussions wit 1 cognizant ISI personnel, the ins 3ector determined that the 1989 edition of the code was adopted on Decem]er 1. 1992. for the second 10-year ISI interval of McGuire Unit 1.
This edition of the code revised the inspection requirements for Class 2 components in Table IWC-2500-1.
Category C-F-1. Pressure Retaining Welds in Austenitic Stainless or High Alloy Piping. to include welds in piping located between the refueling water storage tank (RWST) and pump suction isolation valves.
Essentially the revision expanded the boundary of the ECCS to include the aforementioned suction supply piping which was exempt under the earlier.1980 edition of the code. Also through these discussions, the inspector determined that the engineering group that was responsible for identifying the boundaries of piping subject to ISI examination. and the ISI group responsible for generating the 10-year ISI Plan ()lan). failed to revise the )lan to include all the additional welds in t1e ECCS addressed by clanges in the code. Consequently the new population of welds that were subject to ISI examination were not added to the original population of ECCS welds, which resulted in their exclusion from the ISI selection ]rocess. The licensee subsequently revised the ISI plan to encompass tie subject welds.
This failure to include welds subject to examination in the plant's 10-year ISI plan is a violation of ASME Code Section XI requirements.
However, this non-repetitive, licensee identified and corrected violation is being treated as a Non-Cited Violation (NCV). consistent with Section VII.B.1 of the NRC Enforcement Policy:
NCV 50-369.370/98-07-03. Failure to Implement Selection and Examination of ECCS Welds for ISI as Required by the Code.
The above mentioned PIP No. 0-M97-3386. indicated that the piping between the RWST and the pump suction side isolation valves could not be exempt from Code Section XI. Table IWC-2500-1 examination requirements.
c.
Conclusions ISI examinations observed were performed in a satisfactory manner.
NDE j
examiners were well trained and had good knowledge of plant components
'
and applicable procedural requirements.
The licensee's evaluation and documentation of inspection results were consistent with applicable code requirements.
The licensee's failure to update the second 10-year ISI I
'
plan to include all the ECCS welds as required by the applicable code was identified as an NCV.
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M1.3 Ultrasonic Examination of Part Lenath Control Rod Drive Pressure Housina (CRDH) for Planar Indications Unit 1 a.
Insoection Scone (62700. 57080)
The inspector determined by observation and document review the adacuacy I
of the ultrasonic examination performed on the part length CRDH welcs to
!
determine their structural integrity. The examination was based on ASME l
Code Section XI requirements to the extent practical.
j l
b.
Observation and Findinas
!
Ultrasonic examination was performed on the Unit 1. part length CRDHs in order to determine whether certain rejectable weld indications found in
the Prairie Island CRDHs were present at McGuire.
The examination was L
performed by Asea Brown Boveri (ABB) Combustion Engineering in j
accordance with their ultrasonic examination Procedure MC0-800-0001.
,
revision 1.
The procedure had been reviewed and approved by the I
licensee's Level III ultrasonic (UT) examiner.
The inspector determined that the procedure had been qualified for automated ultrasonic
examination of full penetration butt welds, the heat affected zone and adjacent base material using the Intraspect Automated Imaging System.
)
The examination covered both upper and lower welds on each of the eight
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partial length CRDHs.
Examination of the upper weld was performed using a 60' long wave transducer which was used to scan both sides of the
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weld.
Examination of the lower weld was performed using 45' shear and i
long wave transducers.
Scanning was directed in the down direction j
only due to geometry.
The examination was qualified for the detection j
of indications but not for sizing. The inspector observed initial and
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final calibrations and the examination results of upper and lower welds I
on partial length CRDH Nos. M6. D10. and F4.
The examination showed no l
evidence of rejectable crack like indications.
During a review of related documents, the inspector noted that housing and weld materials used at McGuire differed from those used at Prairie Island.
For example, the housings at Prairie Island were made of stainless steel (SS) type 404 material whereas the McGuire CRDHs were made from type 408 SS material.
Weld consumables at Prairie Island included SS 309 for buttering on the housing and SS 308 for welding the housing to the 304 SS base material. At McGuire. Inconel 82 was used for the buttering as i
well as welding the base material to the housing.
!
c.
Conclusion This ultrasonic examination verified that weld defects identified at l
Prairie Island were not present at McGuire Unit 1.
The examination was l
performed with a qualified procedure and well trained personnel with adequate oversight provided by the licensee. The examination was consistent with applicable procedural requirements.
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M4 Maintenance Staff Knowledge and Performance M4.1 Mjissed TS Surveillance a.
Insoection Scoce (61726)
The inspectors evaluated licensee actions following identification of a missed TS surveillance involving the reactor building fuel handling crane auxiliary hoist. The inspectors reviewed )lant logs and interviewed operations and maintenance staff mem3ers.
b.
Observations and Findinas
'
On June 18, 1998, the licensee failed to perform a calibration of the i
reactor building fuel handling manipulator crane auxiliary hoist within i
100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of core alterations in the reactor vessel as required by TS
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4.9.6.
The licensee recognized this surveillance oversight during core
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alterations.
The testing had not been completed per PT/0/A/4550/018.
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Reactor Building Manipulator Crane Auxiliary Hoist Load Test.
Upon
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recognition of the oversight, the licensee halted core alterations until j
corrective actions were completed. These actions included performance I
of the surveillance and counselling refueling personnel regarding l
procedural adherence.
The equipment was confirmed operable.
The licensee had performed the surveillance prior to the Unit 1 core l
unload. but failed to complete the surveillance testing within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of core reload.
The failure to complete the required surveillance testing is a violation of TS. This non-repetitive, licensee-identified
.
and corrected violation is being treated as a Non-Cited Violation.
I consistent with Section VII.B.1 of the NRC Enforcement Policy; NCV 50-369.370/98-07-04 Failure to Perform TS Required Surveillance on Auxiliary Fuel Hoist.
c.
Conclusions The failure to perform a required TS surveillance on the auxiliary fuel hoist was identified as a NCV.
M4.2 J_nLQuerable Feedwater/ Containment Isolation Valve 1CF30 a.
Insoection Scope (62707. 61726).
_
The inspectors evaluated licensee procedures and practices following licensee identification of an inoperable containment isolation valve while Unit 1 was in Mode 4 for the End-of-Cycle 12 refueling outage.
b.
Observations and Findinos l
}
On May 29. 1998. the IB steam generator feedwater/ containment isolation i
valve. ICF30, failed to stroke closed within 10 seconds, as required by procedure. on the second actuation during testing on May 29. 1998. The valve stroked closed within the specified 10 seconds on the A train l
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solenoid and failed to meet acceptance criteria using the B train solenoid. The valve stroked in approximately 38 seconds on the B train.
The licensee determined that the accumulator section of the valve actuator had been installed improperly. The installation error resulted in a significant reduction in actuator performance at the lower accumulator operating pressures.
This r.itrogen charged accumulator is designed to provide the safety-related closing function following an engineered safety feature (ESF) signal. Reviews of licensee documentation indicated that previously, the actuator had been completely disassembled for troubleshooting activities following identification of potential hydraulic fluid degradation (See LER 50-j 369/97-01).
During the troubleshooting, the actuator was disassembled.
inspected, cleaned and reassembled. The licensee determined that during this maintenance activity, the actuator was improperly reassembled.
Consequently. ]oor work practices were identified as the root cause for this event.
T1e inspectors reviewed the troubleshooting procedures and noted that procedural weaknesses also contributed to the installation errors.
The guidance provided did not include detailed accumulator f
reassembly instructions or caution.s to preclude improper installation.
The licensee has identified additional corrective actions to revise the procedure to provide sufficient instructions for actuator assembly.
The inspectors also noted that the surveillance test procedure for verifying operability of the valve and actuator did not require testing of the valve actuator at lower accumulator o)erating pressures to ensure i
reliable operation. This method may lave been more effective in identifying the installation error. The Unit I hydraulic actuators were subsequently upgraded to pneumatic. The licensee also radiographer the j
Unit 2 hydraulic actuators to assure a similar problem did not exist.
j These actuators are also scheduled to be upgraded to pneumatic during
the next Unit 2 refueling outage.
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The failure to properly reassemble the actuator for valve ICF30 is identified as a violation of TS 6.8.1.
However, this non-repetitive.
licensee-identified and corrected violation is being treated as a Non-Cited Violation. consistent with Section VII.B.1 of the NRC Enforcement
Policy: NCV 50-369.370/98-07-05: Inadequate Procedure for J
Feedwater/ Containment Isolation Valve Reassembly.
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c.
Conclusions A non-cited violation was identified for not providing sufficient
procedural guidance for assembly of a Unit 1 main feedwater/ containment l
isolation valve actuator.
Current testing may not be effective in
identifying actuator performance issues.
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M8 Miscellaneous Maintenance Issues (92902)
I M8.1 (Closed) URI 50-362 J/0/98-06-02:
RWST Intprior Coating IneDection j
I a.
Insoection Scope (62700)
l This URI was identified to review the licensee's evaluation concerning
!
inspection of the interior surfaces of the RWSTs and coating material for operability purposes.
l b.
Qh.servation and Findinos While performing a Unit 2 refueling water and ECCS reliability review, the licensee's engineering group questioned the need for code required
IS] inspections on the RWST and the need for inspecting the protective
'
cc,ating applied to the interior surface of Unit 1 RWST during construction.
This concern and the subsequent actions taken to resolve this issue were documented in PIPS 1-M98-0249 and 0-M97-3386.
The inspector reviewed the above-mentioned PIPS, related drawings.
calculation MCC-1148.00-00-0048 and held discus.sions with the cognizant system engineer.
Through this work effort the inspector determined the i
fol1owing-
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Initially, engineering believed that the RWST for Unit 1 was made l
of carbon steel material and that the Unit 2 RWST was made from I
stainless steel material which would not have a protective l
coating.
This determination was based, in part. on historical
.
information and a visual inspection of the outer surface which l
determined that the Unit 2 RWST was made of stainless steel.
I However. PIP 0-M97-3386 dated September 19. 1997, indicated that i
upon further investigation, it was determined that both tanks were I
made of carbon steel material and that both would require a visual examination of the internal coating surfaces in the near future.
This would indicate that the licensee had not maintained accurate records on the RWSTs and had not developed a plan for inspecting the ad"quacy of the protective coating prior to the aforementioned PIP.
The RWSTs were designed as water storg e tanks in accordance with
the American Water Works D100 Standard and as such were not subject to ASME Code Section XI. ISI requirements.
Both RWSTs at McGuire were fabricated from carbon steel material
conforming to ASTM A283-C specification. The suction pipe is submerged in the borated water 100 percent of the plant operating time. This pipe is made of stainless steel type 304 material and as such the welds between the PWST and the branch pipe are dissimilar metal weld joints.
These welds require periodic ISI i
examination per ASME Code Section XI requirements.
The coating material applied'to the internal surfaces was
.
identified as Plasite 7155.
This was uhe same material used to l
_ _ _ _
coat the licensee's Oconee borated water storage tanks.
The above mentioned PIP 1-M98-0249. indicated that design engineering i
correspondence determined that the service life of the coating was approximately 10-years.
How s er on June 1. 1998, the coating manufacturer provided a memorandum which stated that Plasite 7155 could perform well for 15-20 years in various services with periodic maintenance programs. A visual inspection of the interior surfaces for the Oconee tanks revealed that the coating was in a relatively good condition but that it had undergone some degradation at certain weld locations.
These areas were cleaned and recoated with a similar material provided by the same vendor.
At McGuire, inspection requirements, acceptance criteria for
.
defects in the coating and compliance with design code
!
requirements were developed through calculation MCC-114800-00-
'
0048.
This calculation was primarily based on the ASMC Ccde Section III. Subsection ND requirements and included Electric Power Research Institute Boric Acid Corrosion Guidebook and the tank's design calculation MCC-1201.04-00-0002, which was developed by Chicago Bridge and Iron Company.
McGuire's RWSTs have been 'in service for about 17 years.
The
licensee's operability evaluatiori was based on 20 years of service life and used the corrosion rate of 0.007 inches
]er year.
published in EPRI's Boric Acid Corrosion Guidebooc.
This evaluation indicated that the total wall loss over the 20 year service life would be equal to 0.140 iriches.
Allowing for this j
amount of metal loss in the proximity of the defect, the
!
calculation showed that the minimum available material thickness met design basis requirements in four out of the five shell courses.
However, the calculation showed that the minimum t
available wall thickness for shell course number 3, would be less
!
than the niinimum required by design after 20 years, by approximately 0.020 inches (i.e.
0.11 inches minimum available verses 0.130 inches required).
As such. the licensee has scheduled a visual inspection of the interior surfaces to be performed during 1EOC-13 and 2E0C-12 for Units 1 at:d 2 respectively.
The inspector considered this evaluation and plans I
for inspection an appropriate course of action.
c.
Conclusion i
The inspector concluded that the licensee's evaluation of the protective coating used on the interior surfaces of the RWSTs and the calculations performed to determine acceptance standards for operability were satisfactory.
This item is closed.
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JII. Enoineerinq E2 Status of Engineering Facilities and Equipment E2.1 EDG Reliabilj.ly Followina Sub-Component Failures a.
InsDigljijn SCoDe ca7sso. 37ss1. 62707)
The inspectors reviewed the conditions related to the recent negative
]
trend in EDG sub-component failures.
The inspectors reviewed the
{
licensee's extent of condition inve.stigation which included analyses to identify component failure arecursors and licensee actions to assure reliabih ty of the EDGs. T1e inspectors observed selected portions of corrective diesel maintenance and post-maintenance EDG operability runs.
The root cause investigation activities and findings are discussed in i
detail in Section E4.1 of this report.
b.
Observations and Findin_qs During the three week period between May 19 and June 4.1998, the
)
station experienced a trend of EDG sub-component failures.
All I
component failures occurred in the cylinder heads which had been rebuilt I
during the 1997 outages on both units. The heads were rebuilt by an
{
approved Appendix B vendor at the vendor's facility as part of a 100 percent EDG refurbishment.
At the time of the failures, there were less
{
,
than 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> run time on any EDG since the completion of the rebuilds.
l There were four component faiiures on three EDGs. One failure resulted j
in the potential inability of the EDG to meet its design function.
A
'
licensee event report (LER) was issued on July 2. 1998. for the June 3, 1998, identification of the dropped exhaust valve seat.
l May 19. 1998 A broken exhaust valve insert was discovered on EDG 1A. cylinder 6R.
The condition was identified during the monthly surveillance test when low exhaust temperatures were noted on this cylinder.
In reviewing i
historical diagnostic information, the licensee identified that the initial valve insert defect occurred shortly after the completion of the rebuild on this EDG.
The catastrophic failure which impacted the cylinder combustion capability occurred during the May 19, 1998.
surveillance run.
The licensee attributed this to infancy failure of the valve seat as this initiating defect occurred at approximately 4000 cycles which was less than the ten million cycle threshold after which infancy failures are not ex3ected.
During the catastrophic failure, all broken parts were captured )y the turbocharger screen and the diesel was capable of carrying its design load with one cylinder not functioning.
A failed exhaust seat is detectable by reviewing exhaust temperatures
'
which is routine diagnostic information. The inspectors reviewed the diagnostic data for the other EDGs.and identified no additional low exhaust temperatures indicating a broken exhaust valve and no abnormal
i
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hw temperature anomalies (at no load conditions) that are indicative of imminent seat failure.
j Mav11L 1998 A sticking intake valve was discovered on EDG 18, cylinder BR. The condition was identified at-the end of a 24-hour surveillance run.
i Abnormal engine noise and decreased exhaust temperature were observed at near the end of the run.
For approximately 3 minutes, the IB EDG turbocharger was at approximately 1300 F which exceeded the 1200 F
{
design limit.
The licensee's investigation from diagnostic vibration data indicated that the intake valve was sticking.
Disassembly of the head identified that the intake valve stem to valve guide clearance was insufficient.
Although the vendor used the original manufacturer tolerances, the clearance was not ade.quate.
These values had been changed in the vendor manual and later station EDG maintenance procedures. The licensee's station cylinder rebuild procedure and the vendor manual specified a greater tolerance for the stem to stem guide clearance, however, this procedure was not used by the vendor.
The increased clearance value was not included in the EDG design specification. MCS-1301.00-00-0007 Nordberg Diesel Replacement Parts. Revision 6.
The precursors for this component failure were detectable by review of diagnostic information for engine vibration and EDG performance information.
The licensee's review of this information identified one other cylinder. EDG 1B cylinder 6L. with a potential valve seating problem.
Both the original intake valve and the additional valve were removed and the valve guide bore increased to provide adequate clearance for valve operation.
The inspectors reviewed the diagnostic information on all EDGs and identified no additional indications of valve sticking.
I As previously stated, the licensee determined that the EDG would be i
capable of carrying it design load with one cylinder with inadequate combustion.
For the turbocharger issue, the licensee attributed the increased temperature to o]erator error.
In an attempt to reduce load to compensate for t1e cylinder problem, the operator inadvertently pushed the raise load button for governor control.
This resulted in the load increase to approximately 4.500 Kilowatts (kw) (i.e.
greater than 110 percent of rated load).
Based on a vendor recommendation, the licensee inspected the turbocharger and found no damage.
June 3. 1998 (
A dropped exhaust valve seat was discovered on EDG 2A, cylinder 7L.
-
This was identified during maintenance to repair a stuck hydraulic lifter on the inlet valve.
The dropped seat was discovered without running the EDG.
Technicians were not able to obtain compression on the 7L cylinder while barring the engine.
Visual inspection confirmed that the exhaust seat had dropped out after completion of the previous
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monthly operability run. The lack of significant seat damage. Other than some scoring from barring the engine and diagnostic information
,
f indicated the failure occurred after engine shutdown.
During the previous monthly surveillance run on May 12, 1998, the stuck
'
lifter resulted in high temperature of the 7L cylinder.
During the post-run cooldown, a large temperature variation was experienced between the exhaust valve seat and the cylinder head. The temperature variation and subsequent difference in cooling contraction between the seat and head degraded the shrink fit.of this component and allowed the seat to loosen.
The degra d d seat inhibited the compression of cylinder 7L.
The licensee replaced the head on cylinder 7L.
$
This component failure was detectable by review of the routine l
diagnostic information.
The ]otential for this component failure is
)
indicated by high cylinder ex1aust temperature while loaded and
{
accelerated cylinder cooling after unloading the EDG. The inspectors
reviewed the current diagnostic information for all the EDGs and i
identified no additional indications of this component failure.
Interim corrective actions included revising the EDG operating procedure to decrease the rate of EDG cooldown on shutdown I
Licensee Event Report (LER) 50-370/98-02. dated July 2, 1998, was issued to address the iDG in operability associated with this sub-component failure, June 4. 1998 A broken exhaust valve spring was discovered on EDG 2A. cylinder 4L.
,
This was identified during the post-maintenance testing and diagnostic i
information review following the June 3. 1998, dropped exhaust valve I
seat insert discussed above. The failure was initiated during the post-maintenance test run as indicated by lower than normal cylinder exhaust temperature and momentary increased peak firing pressure which indicated a problem with combustion performance in the cylinder. The 4L cylinder l
head was removed and the broken spring was discovered. This was the
!
outer of two concentric springs on the exhaust valve. As demonstrated by the completion of the 8-hour run, the EDG was capable of carrying its
design load with the broken spring installed.
l The broken spring condition was detectable by review of diagnostic data, in particular, lower than normal exhaust temperature and increased peak firing aressure which indicated a combustion problem with a cylinder.
Althoug1 the licensee identified no definite precursors to a broken spring the indicators provided a method to determine if other broken s) rings were installed.
Review of the diagnostic information indicated tlat no additional broken springs were installed.
Due to a suspected material problem with the new springs, the licensee replaced all the vendor installed springs, with the exception of one inner spring, with the original springs for all EDGS., This was completed on June 16. 1998.
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c.
Cp_qcjusion Overall, the licensee response to each of the EDG sub-component failures was good.
Investigation to determine extent of condition was good and actions to assure reliability of the EDGs was appropriate.
Engineering personnel made good application of newly acquired, advanced engine acoustic and vibrational diagnostics to identify subtle changes in EDG performance.
Failure precursors or indicators were identified for each of the four sub-component failures which could be assessed from diagnostic information.
Additional 24-hour runs of each EDG were accomplished to provide diagnostic information for evaluation of additional potential sub-component failures.
E2.2 Unit 1 Post-Irradiation Fuel Inspections and Fuel Handlina Activities a.
Insoection Scone (37551)
The inspectors reviewed the results of spent fuel pool (SFP) inspections
'
of Unit 1 assemblies removed at the end of operating cycle (E0C) 12 and a configuration management issue involving a burnable poison (BP)
assembly.
b.
Observations and Findinas During the Unit 1 refueling outage (RFO), the licensee conducted pool side UT and visuel examination of discharged fuel from operating cycle number 12.
One suspected leaking fuel rod as confirmed and pinpointed
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to a thrice burned assembly. This leaking fuel rod had indication of internal hydriding.
However, fuel reliability at McGuire continued to be very good.
During preparations for fuel shuffle in the pool (1E0C12), the licensee identified that a burnable poison assembly was located in a cell that
)
was thought to be empty.
During a fuel reconstitution of assembly K-45
'
last summer. the licensee relocated a BP assembly to cell NN-10 (region II of the SFP).
Engineers failed to update the SFP inventory map following movement of the subject BP. A root cause investigation was completed that revealed procedural deficiencies and human performance issues.
A map update was needed following movement of the BP assembly to cell NN-10: however, the responsible individual inadvertently overlooked the actual transfer step requiring an update when procedure OP/0/A/6550/011. Internal Transfer of Fuel Assemblies, was completed.
The individual misinterpreted the data which resulted in not recognizing that an update was required.
The procedure also lacked clear and specif.ic steps to update the SFP maps following internal transfers.
Corrective actions included corrections to the SFP inventory map and special nuclear material (SNM) data bases.
No procedere change was made
,
because procedural enhancements had been incorporated since the reconstitution of K-45 assembly that specifically required an update to the SFP map and SNM data bases. The inspectors considered configuration management of pool inventory significant; however, this failure had i
minimal actual safety significance since the licensee does not take l
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credit for burnable poison rods in SFP criticality analyses.
The inspectors discussed the issue with site management and noted that the issue has received appropriate management attention.
The failure to accurately track the location of the burnable poison was identified as a violation of TS 6.8.1.
However, this non-repetitive.
licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy:
NCV 50-369/97-07-06. Incorrect Unit 1 Spent Fuel Pool Configuration Map Update.
c.
Conclusions Fuel inspection activities were good and confirmed a suspected leaking fuel rod in thrice burned fuel.
A NCV was identified for a spent fuel pool configuration management issue involving a burnable poison assembly located in a pool location which was thought to be empty.
Fuel reliability at McGuire continued to be very good.
E4 Engineering Staff Knowledge and Performance E4.1 Root Cause Investigation of EDG Sub-Comoonent Failures a.
Inspection Scone (37550. 37551)
The inspector reviewed the licensee's root cause investigation for the EDG sub-component failures which occurred between May 19 and June 4.
1998.
b.
Observations and Findings The extent of condition reviews adequately identified failure arecursors or indicators for each of the four failed sub-components. Wit 1 these precursors identified, the licensee was able to determine that the failures were not common to all of the EDGs.
In conjunction with the replacement of valve springs, this provided assurance of the reliability of the EDGs.
This was discussed in Section E2.1 of this report. The root cause investigation was in progress and included long term investigation activities such as laboratory testing of materials.
One potential common mode failure mechanism was identified related to the failed spring.
May 19. 1998 The EDG 1A broken exhaust valve insert was attributed to infancy failure of the component part due to the fault initiation at the early cycle life of the component.
The preliminary results indicated this was a random failure and not attri)utable to vendor or licensee performance as
'
a root cause. Metallurgical examination results were inconclusive. The licensee is performing a finite element analysis to ascertain a root cause. A previously identified Inspector Followup Item. IFI 50-369 370/98-06-01 will remain open pending inspector review of computer analysis results.
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May 31. 1998 The EDG 1B sticking valve seat was attributed to inadequate valve stem to stem guide clearance. The root cause was vendor performance in that an inadequate valve stem to valve guide clearance criterion was used by the vendor for this parameter. The criterion used by the vendor was not consistent with the current vendor manual or licensee procedure.
The licensee's vendor oversight failed to identify that the vendor was using outdated procedures and criteria.
The vendor. NAK Engineering, was qualified by Duke Power as an Appendix B vendor, th ough an audit at the vendor facility in 1995, and annual documentation review for performance thereafter.
During the rebuild of all EDG cylinder heads. 64 total, there was limited licensee oversight 3rovided at the vendor facility.
The actual rebuild work was performed Jy a vendor of NAK Engineering using NAK procedures and qualified by NAK engineering.
The rebuild procedures used by the vendor were from the original manufacturer. The licensee identified that the McGuire station procedure for cylinder rebuild. MP/0/A/7400/016. Nordberg Diesel Engirie Cylinder Head Corrective Maintenance. revision 18. the vendor manual.
MCM 1301.00-78. Instruction Manual for Nordberg Diesel Engine Built for Duke Power Company, dated June 24, 1975, and the procedures used by the vendor were inconsistent with respect to the valve stem to stem guide tolerances.
In particular, the Nordberg vendor manual specified 3.5 to 5.5 mils clearance and the station procedure specified a clearance of 3.5 to 8 mils while the value in the drawing used by the vendor was 2 to 4 mils.
The vendor stated to the licensee that they were using original manufacturer procedures for the rebuild and a station rebuild procedure for reference.
Tha inspectors noted that the McGuire reference 3rocedure used by the vendor was dated in 1990 and was several revisions )ehind the same 1997 rebuild procedure used at the station.
The vendor qualification audit and any other activity oversight failed to identify these discrepancies. This is an example of a failure to conduct adequate oversig1t of contractors resulting in the use of products or services that are of defective or indeterminate quality.
This is contrary to the requirements of 10 CFR 50 Appendix B Criterion
'
Vll. Control of Purchased Material. Equipment, and Services.
This is identified as Violation (VIO) 50-369.370/98-07-07. Inadequate Vendor Oversight of EDG Refurbishment. Two Examples.
June 3. 1998 The dropped valve seat on EDG 2A. was a result of system conditions developed after the completion of the EDG refurbishment and was not attributable to vendor performance. The stuck hydraulic lifter on l
cylinder 7L was identified on May 12, 1998, during the monthly surveillance test.
The valve seat dropped on the cooldown following
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this surveillance because the cylinder stopped in a position that allowed increased cooling air flow through the cylinder past the valve seat resulting in the large temperature differential between the valve seat and the cylinder. The large temperature differential degraded the shrink fit of the seat insert.
The licensee indicated that sticking
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hydraulic lifters were not uncommon and generally occur after the EDG has been idle The malfunctioning lifter condition was documented on work order l
98047322, dated May 12, 1998.
Engineering elected to delay the repair until the next EDG 2A down day (the following month) and returned the
!
l EDG to service since it successfully completed its surveillance test.
l Although the cylinder 7L temperature was high at approximately 900*F. it was within the vendor specified operability limit of 960*F and the
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turbocharger inlet temperature was normal.
In discussion with the inspectors, the licensee stated that Duke Power and industry experience
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indicated that a malfunctioning hydraulic lifter did not in itself make an EDG inoperable and this was supported by the successful surveillance run.
The licensee's decision to delay the lifter repair did not create the conditions which caused the valve seat drop however, the delay
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eliminated an o)portunity to identify the dropped valve seat that was identified on t1e following. surveillance run on June 3,1998. This i
contributed to the length of time the EDG was in a degraded condition.
The dropped valve seat insert occurred due to unanticipated system
'
conditions, i.e., the combination of lifter malfunction and the position of that specific cylinder at EDG shut down.
The corrective actions included revising the EDG o erating 3rocedure to increase the engine cooldown hold time at each lateau w111e unloading the engine June 4. 1998
,
The EDG 2A valve s) ring failure was a result of deficient material specification of t1e valve springs installed by the vendor and was attributed to a vendor performance deficiency. The vendor initiated a 10 CFR Part 21 report on this issue.
The licensee investigation included analysis of the material composition of the springs.
With the exception of one inner spring, all EDG intake I
and exhaust springs were replaced with the original springs. The
!
re)lacement new springs installed by the vendor during the cylinder head re]uilds were analyzed.
Four of the springs installed during the rebuild did not meet the original manufacturer or alternate NAK Engineering recommended material specifications. The broken spring was one of the four of unacceptable material specification.
On June 9. 1998, the licensee sampled four springs (three new springs including the failed spring and one old spring). Two of the new springs (including the failed spring) contained a fully (360 degrees)
!
decarburized layer approximately 5 to 7 mils thick (this value exceeded l
l-the ASIM A877 standard that is s)ecifically for valve springs).
i However, the licensee believed tlat no potential common mode failure (CMF) existed because, unlike the failed spring no micro cracks were i
observed on the springs examined.
It was presumed that all of the outer springs came from the same lot.
The inspectors observed and commented to the licensee that the l
!
significant variation in decarburized layers and hardness differences l
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observed 'under destructive examination suggested a mixed lot.
Approximately 2 weeks following the spring failure, the licensee determined that the material composition of four springs were consistent
{
with ASTM A229 which did not include appropriate amounts of silicon, vanadium. and chromium. -These alloys were added to improve the fatigue strength of the springs. -The vendor aurchase orders (P0) for the rebuild service was documented on P0 MN 16070 dated June 11, 1996. The vendor documented on a certificate of compliance, dated March 7,1997, for cylinder heads 7R, 6R, 8L. 8R, and 5L that components furnished in the repair were in accordance with the Duke Power Specification MCS-1301.00-00-0007, rev. 3. The licensee's material analysis determined that the four ASTM A229 specification springs did not meet the original manufacturer's specification. AISI 6150. or the defacto ASTM A401 material specification springs previously provided to and accepted by the licensee.
The remaining springs were of a composition consistent with ASTM A401 which included less vanadium, silicon, and chromium than the original manufacturer material specification AISI A 6150.
The ASTM A401 material specification for the springs had been recommended and provided by the vendor of record, NAK Engineering, since 1991 for all applications of Nordberg diesels. The licensee's specification for EDG replacement parts, MCS-1301.00-00-0007. Nordberg Diesel Replacement Parts, revision 1-6. required original replacement parts to Nordberg specifications unless otherwise specified. The licensee's material analysis following this spring failure was their first awareness that the spring material had been substituted.
NAK Engineering had been aware of this substitution but had not informed the licensee as required by the EDG Replacement Parts Specification provided to the vendor. As a result the licensee did not have the opportunity to evaluate and accept this change in component design. The licensee was in the process of evaluating the new material specification.
The initial findings were that the ASTM A401 material was an acceptable replacement. The vendor had been providing this alternate spring to the licensee since 1993. This change in the material specifications had not been identified by the licensee vendor qualification audit and is another example of inadequate vendor oversight. This is contrary to the requirements of 10 CFR 50 Appendix B Criterion VII. Control of Purchased Material Equipment, and Services.
This is identified as a second example of Violation (VIO) 50-369.370/98-07-07.-Inadequate Vendor Oversight of EDG Refurbishment. Two Examples.
c.
Conclusions -
Engineering root cause investigations for recent emergency diesel
,
generator subcomponent failures were incomplete at the end of the
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l inspection aeriod.
However, the investigation has been comprehensive and thoroug1.
Two of the four failures were attributable to vendor performance deficiencies and a violation was identified for inadequate oversight of vendor activities for EDG repair.
One component failure
.was attributed to infancy failure and the last was attributed to unanticipated system interaction. Corrective actions com)leted have been adequate to assure the continued reliability of the EDG ___ - _
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E4.2 Enaineerina Backloos l
a.
Insoection Scope (37550)
l The inspector reviewed the backlog of engineering work responsibilities l
to assess the cuality of engineering plant support.
The backlog items
reviewed incluced revisions to drawings and calculations, engineering assigned action items on PIPS, temporary modifications, control room instrumentation problems (CRIPs), operator workarounds, and maintenance work orders on engineering hold.
b.
Observations and Findinas The licensee monitored the outstanding work in each of the activities reviewed and backlogs were relatively small. The status of backlogs was periodically reviewed by management.
Backlogs were defined as those work items which did not meet the licensee's program requirements.
The licensee program requirements for the activities reviewed were reasonable.
For example, drawing revisions resulting from modifications were required to be completed within 120 days of modification completion by Nuclear Station Directive (NSD) 301. Nuclear Station Modifications (NSMs), revision 13.
The modifications manual established a more limiting goal of 30 days for vital to operations (VTO) drawings and 75 days for non-VTO drawings. All control room VT0s were updated before the modification was accepted by operations. There were less than 50 drawings identified as backlog.
Calculations which were controlled as drawings, included an additional 17 items as backlog.
Engineering was assigned responsibility for approximately 50 percent of station PIPS.
PIP performance measures and program goals which were tracked included 30 days for problem evaluation and six months for assigned corrective action items. Aggressive performance goals established in January 1998, included less than 15 problem evaluations greater than 30 days and less than 25 action items greater than six months. The current backlog exceeded these goals with 35 3roblem
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reports greater than 30 days and N action items greater tlan six
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months.
This was not a concern because the recently established goals were intended to be aggressive and the actual number of backlog PIP items was relatively small. Approximately 1750 PIPS had been assigned to engineering since January 1998.
Overall. the number of open PIP
!
items had been trending down since January 1998. indicating that these were adequately monitored and overseen by management.
Backlogs of remaining items were relatively non-existent. There were 14 temporary modifications installed one of which was on a safety related l
l system.
This was installed for less than one year. There were 22 CRIPs l
down from 60 in January 1998.
Operator workarounds were less than the
!
established program goals.
There was one work order on engineering hold for greater than 30 days.
The inspector reviewed the outstanding work items with the assigned responsible supervisors and verified that no safety significant work l
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' items were included in the backlogs. The responsible individual was cognizant of the outstanding work and had established schedules for completion.
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c.
Conclusions
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The backlog of engineering work was relatively minor.
Outstanding work was appropriately monitored and evaluated for significance.
The small
.
l backlog indicated that appropriate engineering resources were focused on i
completing engineering activities.
E4.3 Nuclear Station Modifications a.
Insoection Scope (37550)
The inspector reviewed the design documentation and observed initial installation activity for selected Unit 1 outage mMifications.
These included the nuclear. station modifications (NSMs) to the main feedwater system (CF) isolation valves, auxiliary feedwater system (CA) isolation valves, and the RWST level instrumentation and enclosure.
b, Observations and Findinas NSM MG-12505. Reclace CF Isolation Valve Actuators and Modify Valve Internals. dated May 21. 1998 This modification replaced the existing hydraulic operators for the CF containment isolation valves with operators using nitrogen gas.
Additionally, the valve internals were modified to use a parcilel disc gate valve rather than the existing wedge type gate. The 50.59 evaluation for the modification was comprehensive and well detailed.
The planned post-modification testing (PMT) was adequate.
During the
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PMT the licensee identified a design defect for the valve operators. On l
loss of instrument air the four-way valves, which direct air to open ar.d
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close the CF isolation valve, reach an unstable intermediate position
which results in venting the nitrogen storage tank. The tank provides i
the motive force for the CF isolation valves and was sized to assure the valves will remain closed for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> on an isolation signal.
The item -
was identified on PIP 1-M98-2243, dated June 24, 1998.
The item was being adequately addressed consistent with the safety significance of the issue. The licensee was investigating a design solution to resolve the issue.
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NSM MG-12475. Reclace Unit 1 CA Turbine Driven and Motor Driven Pumos'
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Isolat. ion Valves. dated Acril 13. 1998 j
This modification replaced the existing CA pump isolation wedge type gate valves and Rotork and Limitorque operators with parallel disc gate valves and a different model Rotork operator. TM 50.59 evaluation was comprehensive and well detailed. The post-modification testing was adequate to verify the design function of the valves.
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HSM MG-12496. Unit 1 RWST Level Indication and Enclosure. a ad Aoril 6.
1228 This modification replaced the safety related narrow range level instrumentation with safety related wide range level indication and provided an enclosure to improve freeze protection. The 50.59 safety evaluation was adequately detailed.
The scheduled PMT was adequate.
The following documentation was reviewed to verify the RWST level set points and zero reference level were consistent for design analysis, instrument calibration, and operating procedures:
MCC 1223.12-00-0010. Minimum Available NPSH for Emergency Core
.
Cooling System Pumps Revision 1 l
MCC 1552.08-00-0118. RWST Level Set Point, dated December 10, 1997
.
MCC 1210.04-00-0068. Instrument Loop Uncertainty for RWST Level
.
(Loops FW-500, 501, 502) per NSM MG-12496 & MG-22496, dated September 17. 1997 MCC 1223.21-00-0016. RWST Level Set points and Volumes per NSM MG-
.
12496 and MG-22496. dated September 18. 1997 l
IP/0/A/3050/013. RWST Class 1E Level Transmitter Calibration
.
Procedure. Revision 16 EP/2/A/5000/ES-1.3. Transfer to Cold Leg Recirculation Procedure.
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Revision 7 The zero RWST reference level was consistent between the calculations l
and calibratio1 procedure.
Containment swapover initiation from the low level set. point was adequate to provide the required net positive suctionhead(NPSH)fortheECCSpumps.
lne referenced RWST level in the emergency procedure for manuai swapover was adequate to assure the required pump NPSH. The level set )oint and instrument uncertainty calculations adequately addressed t,e impact of vortex formation, density variations due to temperature and boric acid concentration, and instrument. loop error.
,
During'the modification implementation, there was an inadvertent loss of
'
the RWST temperature instrumentation loop (1FWLP5030), which was an instrument required by TS. Work order (WO) 97107743. task 25. dated May 30, 1998, was revised on May 29, 1998. to include de-energizing of the terminal strip that powered the RWST level and temperature instrumentation loops.
The work instruction was initially reviewed by the project management group, which included engineering, maintenance.
and operations staff, on April 6,1998. The revision to de-energize the terminal strip was for personnel safety concerns. This revision did not
,
clearly communicate the loss of the RWST tem)erature instrumentation loop and there was no additional review by t1e aroject management group.
These factors contributed to the inadequate wor ( instruction in the implementation of NSM MG-12496. The affected unit was in Mode 5. and
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there were no fuel movement or reactivity addition activities in progress.
In accordance with TS 3.1.2.1. the boric acid tank (BAT) via the boric acid transfer aump and charging pump was established as the boron injection flow pat 1.
The item was identified on PIP 1-M98-1668 dated June 1. 1998. This non-repetitive, licensee-identified and
.
corrected violation is being treated as a NCV consistent with Section i
VII.B.1 of the NRC Enforcement Policy and is identified as NCV 50-369/98-07-08. Inadequate Work Instruction for NSM MG-12496. RWST Level Modification.
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While implementing NSM MG-12496, operations demonstrated a performance weakness related to an inadequate awareness of shutdown conditions.
During the RWST modification the established boron injection flow path was via the BAT. transfer pump and charging pumps due to the loss of the RWST temperature instrument. However, on June 4.1998, this flow path was lost due to tagout of the boric acid flow meter.
This was identified by the licensee when the boron injection valve line-up verification was performed. As previously discussed the RWST flow path was technically in-operable due to the de-energized temperature loop.
The licensee had established the capability for local temperature monitoring, however, this was not initiated when the BAT flow path was tagged out. The TS required the RWST temperature to be verified every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when the outside temperature was less than 70 F.
There was no documentation related to the tag out that verified the outside temperature was greater than 70 F.
This item was not safety J
significant in that, it can be assumed, based on the seasonal conditions, that the RWST was greater than 70 F.
Additionally, the unit was in Mode 6 with no fuel movement or reactivity addition activities in progress.
c.
Conclusions The design documentation for reviewed Unit 1 modifications was adequate.
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The 50.59 safety evaluations were comprehensive and well detailed. The design documents and operating procedures related to the RWST level modification were consistent with respect to reference levels and set points. Two performance deficiencies were noted during implementation of the RWST level instrumentation modification: an NCV was identified for inadequate work instructions and an operations performance weakness was identified for inadequate awareness of shutdown conditions.
IV. Plant Support R1 Conduct of Radiation Protection and Chemistry R1.1 Tour o'f Radiological Protected Areas a.
Insoection Scooe (83750)
l The inspectors reviewed implementation of selected elements of the licensee's radiation protection program.
Requirements were identified in Title 10 CFR Parts 20.1201. 1501. 1502. 1601. 1703. 1802, 1902 and
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1904.
The review included observations of radiological protection activities including control of radioactive material, radiological surveys and postings, radiation area controls, and high radiation area controls b.
Observations and Findinas During tours of the auxiliary building and radioactive waste storage and handling facilities, the inspectors reviewed survey data and performed selected independent radiation and contamination surveys to verify area postings.
Observations and survey results determined the licensee was effectively controlling and storing radioactive material.
The inspectors also observed that extra high radiation areas (locked high radiation areas) were locked as required by licensee procedures and all other high radiation areas observed were appropriately controlled as required by licensee procedures.
The inspectors also inventoried the licensee's extra high radiation area (EHRA) and very high radiation area (VHRA) key control boxes maintained by radiological control and determined that at the time of the inspection, all keys assigned to radiological control for locked EHRAs and VHRAs were accounted for.
Dosimetry controls for the EHRAs and VHRAs observed were established in radiation work permits (RWPs) and special radiation work permits (SRWPs)
as required by licensee procedures.
As of June 1.1998, approximately 25 personnel contamination events (PCEs) defined as greater than 1000 disintegrations per minute (DPM) had occurred during 1998 which included both particles and dispersed contamination events for clothing and skin contaminations. The inspectors reviewed PCE reports prepared by the licensee to_ track, trend, determine root cause, and determine any necessary follow up actions.
The licensee had continued efforts in 1998 to reduce personnel contaminations and was performing large area surveys of passageways 4
times per shift during the outage period to minimize the potential for
'
clean area contaminations.
Contaminated square footage was being maintained at approximately 1 percent of the total radiologically controlled area during the outage period and at 0.5 percent during non-outage periods.
Radiation work permits (RWPs) established for performing work were reviewed. The inspectors determined that RWPs were to be reviewed and understood by workers prior to entering the RCA.
The inspectors reviewed selected RWPs for adequacy of the radiation protection requirements based on work scope, location, and conditions.
For the
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RWPs reviewed, the inspector noted that appropriate protective clothing and dosimetry were required.
During tours of the facility, the inspectors observed the adherence of plant workers to the RWP requirements. The inspectors discussed RWP and SRWP requirements with workers and found those workers interviewed understood their RWP and SRWP requirements.
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c.
Conclusions Based on observations and procedural reviews. the inspectors determined
'
that the licensee met.10 CFR 20 requirements for control of personnel
monitoring, radioactive material, radiological postings, radiation areas controls, and high radiation areas.
RI.2 Occupational Radiation Exoosure Control Proaram a.
Insoection Scooe (83750. 84750)
The inspectors reviewed the licensee's implementation of 10 CFR 20.1101(b) which requires that the licensee shall use. to the extent practicable, procedures and engineering controls based upon sound radiation protection principles to achieve occupational doses and doses
,
to members of the public that are As low As Reasonably Achievable
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(ALARA).
b.
Observations and Findinos The inspectors * review of the licensee's ALARA program determined the licensee had established a challenging annual exposure goal of approximately 137.88 3erson-rem which included a Unit 1 outage goal of 102 person-rem. At tie time of the inspection on June 2.1998, the licensee was tracking approximately 28.5 person-rem for the Unit 1 outage, which was on target with previous estimates of 31 person-rem.
.The-licensee had continued to track and trend outage exposures for i
purposes of future outage preplanning and it was determined that exposures continue to trend downward based on ALARA initiatives.
During tours of the facility the inspectors also observed Radiation Protection (RP) technicians controlling access to work areas to minimize personnel-ex)osure and briefing workers in the work area as radiological conditions clanged during reactor shutdown crudburst and cleanup activities.
The inspectors noted strong management support for ALARA during reactor cleanup activities by extending a. planned cleanup from 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> to reduce source term activity. All personnel radiation exposures during 1998 to date were below regulatory limits.
The inspectors reviewed a PIP form prepared by the licensee to identify a problem that occurred on May 30. 1998 during the Unit 1 shutdown. The problem was the licensee failed to establish procedural guidance for the abnormal vent path used for degassing the Unit 1 volume control tank (VCT) to the environment to reduce hydrogen levels in the nuclear coolan.t (NC) system.
This rasulted in an unplanned release of radioactive material. apprc.4mately 0.409 curies which initiated an auxiliary building ventilation gaseous radiation monitor. EMF-41 alarm.
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The degas evolution occurred for approximately 390 minutes and was eventually stopped following the alarm.
Licensee management was actively involved in the decision to perform the subject degas evaluatio __
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Based on a review of th1 event and discussions with chemistry and RP personnel, the inspectors aetermined the licensee's failure to establish procedural guidance for the abnormal vent path used for degassing the VCT to the environment be identified as violation (VIO) 50-369/98-07-09:
Failure-to Establish Procedural Guidance for Degassing Unit 1 Volume Control Tank.
c. ' Conclusions The inspectors determined the licensee was maintaining programs for controlling exposures ALARA and continued to be effective in controlling overall collective dose. All personnel radiation exposures during to date in 1998 were below regulatory limits.
One violation was identified for failure to establish procedural guidance for degassing Unit 1 volume control tank.
R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Breathina Air and Resoirator Review a.
Insoection Scope (83750)
Title 30 CFR 11.121 requires that compressed. gaseous breathing air meet the applicable minimum grade requirements for Grade D or higher quality.
Title 10 CFR Part 20 Subpart H provides requirements for respiratory protection programs.
Title 10 CFR 20.1501 requires licensees ensure instruments and equipment used for quantitative radiation measurements are calibrated.
b.
Observations and Findinas The inspectors reviewed and discussed with the licensee representatives the program for testing and qualifying breathing air as Grade D.
The inspectors examined breathing air manifolds for physical integrity and current calibration of gauges. -In addition. the inspectors further noted that the supplied air hoods and hoses available for use were comnatible per manufacturer's instructions, as were air supplied respirators and hoses. All respiratory protection equipment observed during facility tours was being maintained in a satisfactory condition.
The inspectors verified personnel issuing respiratory protection had been trained to do so and the current training and medical qualifications for personnel wearing respiratory protection was verified at the time of issue.
During. facility tours, the inspectors noted that survey instrumentation and continuous air monitors observed in use within the RCA were operable
'
and currently calibrated. The inspectors toured the instrument calibration room and discussed the portable instrument program with cognizant personnel. The inspectors determined the licensee had an adequate number of survey instruments available for use during the outage and the instruments were being calibrated and source checked as required by licensee procedure.
,
c.
Conclusions Review of breathing air testing records verified that the licensee was calibrating breathing air compressor equipment and sampling in-use breathing air systems for certification in accordance with procedural requirements.
For the tests reviewed. breathing air met Grade D or better quality requirements. The respiratory protection program was being implemented as required by 10 CFR Part 20 Subpart H.
Survey instrumentation had been adequately maintained.
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F1 Control of Fire Protection Activities F1.1 Fire Reoorts and Investigations a.
Insoection Scooe (64704)
The inspectors reviewed the plant fire emergency reports and the resulting PIPS for 1997-98, to assess trends of maintenance related or material condition problems with plant systems and equipment that may initiate fire events. The inspectors verified that plant fire protection reporting requirements were met in accordance with NSD-112.
" Fire Brigade Organization. Training and Responsibilities." Revision 0, when fire related events occurred.
b.
Observations and Findinas The fire emergency reports and associated PIPS indicated that there were two fire brigade responses to reported fires in the plant during the period 1997-98. One of these incidents involved a small welding slag fire in the Unit I reactor building on March 11. 1997. during the steam generator replacement outage. The other was a leaking forklift propane cylinder that ignited on November 2. 1997, in the plant yard area. In both cases licensee personnel identified and extinguished the fire condition in a timely manner. contained the fire to the original source, and prevented the fire from spreading to other equipment or cables.
c.
Conclusions During 1997 and 1998 there were two incidents of fire within safety significant plant areas. When fires occurred, licensee personnel identified and extinguished the fire condition in a timely manner.
contained the fire to the original source, and prevented the fire from spreading to other equipment or cables.
F1.2 Combustible Material Controls / Fire Hazards Reduction i
a.
Insoection Scooe (64704)
The inspectors reviewed the licensee's administrative NSD 313. " Control of Combustibles and Flammable Material." Revision 1: NSD 116. " Nuclear Chemical Control Program." Revisi6n 0; and NSD 104. " Housekeeping Material Condition. and Foreign Material Exclusion." Revision 13: to j
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determine if they satisfied the combustible control and housekeeping objectives established by the licensee's approved fire protection program.
The inspectors also toured selected plant areas to inspect the licensee's implementation of these procedures.
b.
Observations and Findinas l
During plant walkdowns with the licensee's fire protection engineer. the inspectors observed that controls were being maintained for combustible liquid leaks in areas containing lubrication oil and diesel fuel, such as the diesel generator rooms. Although their were several small leaks from equipment, the leakage was being contained by the use of oil absorption materials that were replaced at frequent intervals.
Lubricants and oils for normal maintenance activities were placed in approved. safety containers and properly stored within approved fire resistive flammable liquids storage cabinets. The flammable liquid storage cabinets were located only in those safety related areas designated by the plant procedures.
The doors of these storage cabinets were properly closed and latched.
g The inspectors also verified that the majority of the wood used during work activities associated with the ongoing Unit I refueling outage was treated to make it fire retardant. The inspectors observed that the work areas were cleaned of unnecessary material. Waste material trash l
cans utilized safety covered lids and were emptied on a frequent regular
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basis.
The inspectors. concluded that the observed practices met the requirements of-the licensee's procedures as described in the UFSAR.
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The various plant departments were properly implementing their I
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responsibilities for combustible material control. The observed level of plant housekeeping reflected good organization and cleanliness practices on the part of plant workers.
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c.
Concl.p_sions
The implementation of procedural requirements for using and storing i
transient: combustibles in safety-related areas was good. The material condition in the plant indicated that the various plant departments were properly implementing their responsibilities for combustible material i-control. The observed level of plant housekeeping reflected good organization and cleanliness practices on the part of..lant workers.
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F2 Status.of Fire Protection Facilities and Equipment F2.1 Egactor Coolant Pumo (RCP) Oil Collection System a.
Insoection Scooe (64704)
The inspectors reviewed the design,' operation, and maintenance of the oil ' collection system for: the reactor coolant pumps to verify that the
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requirements of UFSAR Section 9.5.1, McGuire Unit 1.2 Safety Evaluation
. Reports (SERs) Supplements 5 and 6. McGuire Nuclear Station Technical S) edification 6.8.1.1. " Procedures and Programs." MCS-1465.00-00-0008.
")lant Design Basis S and 10 CFR 50 Appendix R. specification for Fire Protection." Revision 1:
Section III.O. "011 Collection System for Reactor Coolant Pump." were met.
b. Observations and Findinas The inspectors reviewed UFSAR Section 9.5.1. "McGuire Safety Evaluation Reports." Supplements 5 and 6. Section 5.3 " Fire Protection Inside Containment." and Section 9.5.1. " Fire Protection System ~ McGuire Nuclear Station Technical Specification 6.8.1.i. " Procedures and Programs:" MCS-1465.00-00-0008. Section C26.1. " Reactor Coolant Pumps Oil Collection System" Revision 1: MCS-1553.NC-00-0001. Section 31.
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" Unit 1 System and Equipment Descriptions." Revision 3: RCP oil collection system (NC) flow diagram drawing Nos. MCFD-1553-04.00.
Revision 1. operation procedures OP/1/2/A/6100/SU-9. " Mode 4 -
Checklist." Revision 9. and OP/1/2/A/6100/SU-15. " Mode 3a - Checklist"
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Revision 6. PT/1/A/4600/008. " Surveillance for Unit Heatup." Revision 2.
SM/0/A/8400/004 " Reactor Coolant Pump Motor Minor Corrective Maintenance." and other related operator alarm response documentation.
l Based on reviews of engineering drawings, procedures and discussions with the RCP system engineer. the inspectors-determined that the procedural guidance was weak in that it did not verify RCP oil collection system' drain tank fluid level at reactor power operation or assure that, prior to the return to full power following an outage, no oil was stored in the oil collection drain tank. The weakness was that the unmonitored 300 gallon oil collection drain tanks may have oil stored inside, or contain water, and not be able to fully contain a large oil leak of the potential total inventory of RCP oil.
The inspectors verified that each RCP oil collection system consisted of a 300 gallon oil collection drain. tank and associated piping.
The total volume inventory of each RCP oil lubricating system was approximately 265 gallons: thus the available reserve was approximately 35 gallons.
The oil collection drain tank was not provided with a level alarm.
The tank was furnished with a liquid level sight-glass gauge inside the containment behind the biological shield to provide local indication of oil in the tank.
The inspectors also noted that the post-outage pre-startup procedures did not reflect verification that the oil collection drain tanks were empty. The licensee acknowledged the weakness and on
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June 24, 1998. initiated PIP 98-2222 to address the inspection of the
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oil collection drain tank level prior to operation. The inspectors conducted walkdowns of Unit 1 containment and verified that the oil collection drain tanks were empty prior to the Unit 1 restart from the current refueling outage.
The inspectors verified that during plant operation loss of oil from the RCP motor lubrication systems would be detected by the RCP motor oil reservoir hi/lo level alarm.
If the oil level in the oil reservoir of
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any RCP motor reached above or below the normal level, an alarm would be received in the control room prompting the operators to increase monitoring of the available RCP operational parameters such as bearing temperature and motor stator temperature.
c.
Conclusions A fire protection inspection and surveillance testing program weakness was identified for not having procedural guidance to verify the RCP oil collection system tank fluid. level.
Plant operators had sufficient procedural guidance to identify an oil leak from the RCP oil lubrication system of any one of the RCP motors and take appropriate action.
F2.2 Fire Barrier Penetration Seals a.
Insoection Scoce (64704)
The inspectors reviewed the fire barrier silicone foam penetration seal design and testing to verify that the technical guidance of NRC Generic Letter 86-10: NRC Information Notices. 88-04. 88-56, and 94-28: and NUREG-1552, was addressed. The inspectors compared as-built fire barrier silicone foam penetration seals to fire endurance test configurations to verify that the as-built penetration seals reviewed were qualified by appropriate fire endurance tests, representative of, and bounded by, configurations which satisfactorily pared a fire test.
During plant walkdowns the inspectors observed the installation configurations' of approximately 24 selected mechanical and electrical fire barrier silicone foam penetration seals in the emergency diesel generator and auxiliary buildings to confirm that the licensee had established an acceptable design basis for those fire barriers used to separate safe shutdown functions.
b.
Observations and Findinos The inspectors reviewed the fire barrier seal design and testing for 24 of the fire barrier silicone foam seal penetrations. The inspectors
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reviewed Maintenance Procedure MP/0/A/7650/064, " Fire Barrier
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Penetration Installation. Inspection, and Repair " Revision 21: Periodic Test PT/0/A/4250/004. " Fire Barrier Inspection," Revision 14: and Drawings 1315.01 series, " Fire and Flood and HVAC Boundaries" for the location and description of the fire seals: and assessed the licensee's supporting technical justification and any available engineering l
evaluations for the sampled silicone foam type penetration seals.
The inspector's review focused on verifying that the following design and installation parameters for the as-built configurations were adequately bounded and justified by the licensee's engineering evaluations:
penetration opening sizes
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material and thermal mass of penetrating items
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clearances of penetrating items
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unexposed surface temperatures
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The inspectors found that the silicone ty]e penetration seals were covered by 1-inch thick ceraform damming Joards: therefore. it was dif ficult to verify the specific design specifications that had been used during the installation of these penetration seals.
The design
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documents permitted several installation seal options to meet the design requirements.
The specific requirements were dependent on the barrier i
construction thickness of the barrier, and whether the penetration was l
thro;gh a wall or floor fire barrier.
The inspectors determined that I
the as-built seal designs deviated from important configuration attributes (i.e., opening sizes. cable tray fi" material of the penetrating items, clearances of penetrating items, and maximum free area of unsupported foam). The licensee was unable to locate GL 86-10 engineering evaluation documentation that evaluated the adecuacy of the
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deviations fr om a tested fire barrier configuration.
This coes not satisfy the guidance of GL 86-10. The licensee stated that industry documentation is available to support silicone foam penetration seal installations at McGuire.
Based on the results of a recent Triennial Fire Protection OA Audit, the licensee had begun a project to inspect and to revalidate the installation of these penetration seals to s
determine if each penetration was bounded by a specific design I
specification that was substantiated by qualified test documents.
The licensee had initiated PIP 0-M98-1844 to track the completion of this project.
This issue will be evaluated during a subsequent NRC inspection, u)on completion of the licensee's revalidation of the installation of t1e fire barrier penetration seals.
This is identified as Inspector Followup Item (IFI) 50-369.370/93-07-10:
Review of Licensee's l
Revalidation of Fire Barrier Penetration Seals.
c.
Conclusions The fire barrier penetration seals were functional.
However, the licensee did not satisfy the guidance of GL 86-10 for engineering
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evaluation documentation that evaluated the adequacy of the deviations from a tested fire barrier configuration. The licensee had implemented a project to inspect, revalidate the installation of penetration seals, and provide documentatico to identify the design specification and bounding test criteria applicable to each fire barrier penetration.
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F5 Fire Protection Staff Training and Qualification F5.1 Fire Briaade Organization and Drills (64704)
a.
Insoection Scope l
The inspectors reviewed the fire brigade organization and drill program
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for compliance with plant procedures and the approved fire protection program as described in UFSAR Section 9.5.1. " Fire Protection System."
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b.
Observations and finding 2 The inspectors verified that the organization and drill requirements for the plant fire brigade were established by MCS-1465.00-00-0008 ~ Plant Design Basis Specification for Fire Protection." Revision 1. and NSD 112. ~ Fire Brigade Organization. Trainirg and Responsibilities."
Revision 0.
The inspectors reviewed the licensee's fire brigade training matrix reports and records for the fire brigade members and verified that the required training records were up-to-date and a sufficient number of qualified personnel to meet the facilities fire brigade procedure t
requirements were assigned per shift.
A fire brigade drill was not observed during this ins)ection period.
To evaluate drill performance, the inspectors reviewed tie drill evaluation data for the. shift drills conducted for the first quarter of 1998 and verified that the fire brigade response and participation for these drills satished the requirements of the site procedures.
c.
Conclusions The fire brigade organization and drill program met the requirements of the site procedu es. The performance by the fire brigade as documented by the licensee's drill evaluations was good.
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F7 Quality Assurance in Fire Protection Activities
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l F7.1 Fire Protection Audit Reoorts I
a.
Jnsoection Scone (64704)
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l The ine. 2crs re newed the results of a Triennial Fire Protection Audit.$A-95-100(ALL)(RA).whichhadbeenconductedattheMcGuire.
Catawba, and Oconee sites during the period from April 27, 1998, to May 11. 1998.
b.
Observations AnJ Finjin,ng n
The OA organization performed an ensite evaluation of the fire protection program during the time period from April 27, 1998, to May 11. 1998. This audit included an oversight assessment of the fire protection program as applied to fire protection systems fire barrier penetration seal 3rogram, fire loading, maintenance and surveillance procedures, fire arigade training ar.d qualification, transient combustible controls, plant modifications, operability of the safe shutdown equipment and emergency lighting. The inspectors noted that i
l the audit team identified five potential significant findings. These findings were under review for resolution by the licensee. The audit team also identified three less significant recommendations.
The inspectors concluded that the 1998 Triennial Fire Protection Audit of the facility's fire protection program was comprehensive and effective
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in identifying fire protection program performance to the plant management.
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C.pncittsions The 1998 Triennial Fire Protection Audit of the facility's fire protect 1on pivgram was comprehensive and effective ;n identifying fire I
protection program performance to plant management.
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F8 Miscellaneous Fire Protection Issues (92904)
F8.1 (Closed _) Insoector Followuo Item (IFI) 50-369.370/97-09-03:
3-Year Fire System Testing This item was previou. sly identified based on the inspectors' concerns that no specific periodic testing of the McGuire fire suppression system interior loop piping was be ing performed.
Subsequently, the licensee on November 7.1997, performec a special flow test cesigned to verify operability of the auxiliary building fire protection water system to supply the maximum required sprinkler and fire hose system demands.
A review of special test results TP/0/A/1200/041. " Auxiliary Building Flow Test. " Revision 0; design calculation MCC-1??3.49-00-0038. "RF/RY-System Auxiliary Building System Flow Test." Revision 0; periodic test 3rocedure PT/0/A/4400/001M. " Fire Protection Flow System Flow Test."
Revision 6: neriodic test procedure PT/0/A/4400/017. " Fire Pump A and B OperabilityIest." Revision 5: the Vendors' performance data for the installed fire hoses and fire fighting nozzles: and discussions with the facility fire protection engineer revealed that the content and resuhs of the maintenance inspection and periodic test program for the tire orotection water system was sufficient to verify that the auxiliary building fire protection design and surveillance water flow operability requirements.specified in the UFSAR were met. This item is closed.
V. Management Meetinas X1 Exit Meeting Summary The resident inspectors aresented the inspection results to members of licensee management at tie conclusion of the inspection on July 16. 1998.
The licensee acknowledged the findings presented.
No proprietary information was identi fied.
PARTIAL LIST OF PERSONS CONTACTED I
Li2Diee Barron. B., Vice President. McGuire Nuclear Station Bhatnagar. A., Superintendent. Plant Operations Boyle. J., Civil / Electrical / Nuclear Systems Engineering Byrum. W., Manager. Radiation Protection l
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Cash. M., Manager. Regulatory Compliance Dolan. B., Manager. Safety Assurance Evans W., Security Manager Geddie. E.
Manager. McGuire Nuclear Station Peele. J., Manager. Engineering Loucks. L. Chemistry Manager Thomas. K.. Superintendent. Work Control Travis, B., Manager. Mechanical Systems Engineering INSPECTION PROCEDURES USED IP 37550:
Engineering IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying. Resolving, and Preventing Problems IP 57080:
Non-Destructive Examination Procedure Review IP 61726:
Surveillance Observations IP 62700:
Maintenance Program Implementation IP 62707:
Maintenance Observations IP 64704:
Fire Protection Program IP 71707:
Conduct of Operations IP 71750:
Plant Support IP 73051:
Inservice Inspection - Review of Program IP 73052:
Inservice Inspection - Review of procedures IP 73753:
Inservice Inspection IP 83750:
Occupational Exposure IP 84750:
Solid Radioactive Waste Management and Transportation of Radioactive Materials IP 92902:
Followup-Maintenance IP 92904:
Followup-Plant Support ITEMS OPENED. CLOSED, AND DISCUSSED i
OPENED 50-369.370/98-07-01 IFI Unexpected Relay Actuation During Unit 1 LOOP (Section 02.1)
50-369/98-07-02 URI Divider Barrier Patches Left in Containment Building Following l
Outage (Section 02.3)
50-369.370/9B-07-03 NCV Failure to Implement Selection and Examination of ECCS Welds as Required by Code (Section M1.2)
50-369.370/98-07-04 NCV Failure to Perform TS Required Surveillance on Auxiliary Fuel Hoist
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50-369,370/98-07-05 NCV Inadequate Procedure for Main
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l Feedwater/ Containment Isolation Valve Reassembly (Section M4.2)
50-369/98-07-06 NCV Incorrect Unit 1 Saent Fuel Pool Configuration Map Jpdate (Section E2.2)
50-369.370/98-07-07 VIO Inadequate Vendor Oversight of EDG Refurbishment. Two Examples.
(Section E4.1)
50-369/98-07-08 NCV Inadequate Work Instruction for NSM MG-12496. RWST Level Modification (Section E4.3)
50-369.370/98-07-09 VIO Failure to Establish Procedural Guidance for Degassing Unit 1 Volume Control Tank (Section R1.2)
50-369.370/98-07-10 IFI Review of Licensee's Revalidation of Fire Barrier Penetration Seals.
(Section F2.2).
CLOSED 50-369.370/98-06-02 URI RWST Interior Coating Protection (Section M8.1)
50-369.370/97-09-03 IFI 3-Year Fire System Testing (Section F8.1)
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Asea Brown Boveri AISI American Iron and Steel Institute
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ALARA -
As Low As Reasonably Achievable AFW
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Abnormal Procedure ASME -
Ainerican Society of Mechanical Engineers ASTM -
American Society for Testing and Materials BAT
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Boric Acid Tank BP
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Burnable Poison BWI
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Backcock and Wilcox International CA
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Auxiliary Feedwater System CCW
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Component Cooling Water CF
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Main Feedwater System CFR
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Code of Federal Regulations.
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CMF
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Common Mode Failure
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CR Control Room
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Control Rod Drive Housing CRIP Control Room Indication Problems
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DES
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Duke Engineering Services DPM
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Disintegrations Per Minute DRPI -
Digital Rod Position Indication DRWM -
Dynamic Rod Worth Measurement EDG
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Emergency Diesel Generator EHRA -
Extra High Radiation Area l
EIT Event Investigation Team
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Emergency Notification System
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End of Operating Cycle l
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Emergency Procedure i
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Ele'+ric Power Research Institute ESF
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Engineered Safety Feature F
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Fahrenheit GL
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Generic Letter GPM
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Gallons Per Minute
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Heating, Ventialtion, and Air Conditioning
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IFI
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Inspector Followup Item IN
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Information Notice IR
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Inspection Report
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Inservice Inspection
KW
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Kilowatt
LER
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Licensee Event Report
LOCA -
Loss of Coolant Accident
LOOP -
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Main Feed Water
MFWP -
Main Feed Water Pump
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Motor-0perated Valve
MSSV -
NC
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Nuclear Coolant System
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Non-Cited Violation
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NOUE -
Notice of Unusual Event
Net Positive Suction Head
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NRC
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Nuclear Regulatory Commission
NRI
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No Recordable Indication
NRC Office of Nuclear Reactor Regulation
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NSD
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Nuclear Site Directive
NSM
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Nuclear Station Modifications
OAC
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Operator Aid Computer
OMP
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Operations Management Procedures
OP
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Operating Procedure
PCB
Power Circuit Breaker
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Personnel Contamination Event
Public Document Room
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Problem Investigation Process
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Preventive Maintenance
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Post Modification Testing
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P0
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Purchase Order
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Periodic Testing
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0A
Quality Assurance
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Radiogically Controlled Area
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Reactor Coolant Pump
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RF0
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Refueling Outage
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Radiation Protection
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Refueling Water
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Radiation Work Permit
RWST -
Refueling Water Storage Tank
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Standby Auxiliary Transformer
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Safety Evaluation Report
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Spent Fuel Pool
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Steam Generatc:.r
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SR0
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Senior Reactor Operator
SRWP -
Special Radiation Work Permit
Tavg -
Reactor Coolant System Average Temperature
TEDE -
Total Effective Dose Equivalent
TEPR -
Top Equipment Problem Resolution
TM
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Tem3orary Modification
TS
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Tec1nical Specifications
UFSAR -
Updated Final Safety Analysis
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Unresolved Item
US0
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Unreviewed Safety Question
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Ultrasonic Testing
Volume Control Tank
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VHRA -
Very High Radiation Area
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Volt
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Violation
Vital to Operations
VTO
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WAPR -
Workaround Problem Resolution
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Work Order
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