IR 05000369/1997015
ML20198N475 | |
Person / Time | |
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Site: | McGuire, Mcguire |
Issue date: | 10/20/1997 |
From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
To: | |
Shared Package | |
ML20198N466 | List: |
References | |
50-369-97-15, 50-370-97-15, NUDOCS 9711040313 | |
Download: ML20198N475 (25) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION 11
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l Docket Nos:
50-369. 50 370 l
License Nos:
NPF-9. NPF 17 Report No:
50-369/97-15, 50 370/97 15 Licensee:
Duke Energy Corporation Facility:
McGuire Generating Station. Units 1 and 2 Location:
12700 Hagers Ferry Road
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Huntersville. NC 28078
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Dates:
August 10,- September 20. 1997 Inspectors:
M. Sykes. Acting Senior Resident Inspector S. Shaeffer. Senior Resident inspector M. Franovich. Resident inspector D. Forbes. Regional Inspector (Section R1.1)
N. Economos. Regional Inspector (Sections M1.2.M1.3.M1.4)
V. Nerset. NRR. Project Manager (Section E3.1)
Approved by:
C. Ogle. Chief. Projects Branch 1 Division of Reactor Projects Enclosure 2 9711040313 971020 ADOCK0500g39 DR
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EXECUTIVE SUMMARY l
l McGuire Nuclear Station. Units 1 and 2 l
NRC Inspection Report 50-369/97-15. 50-370/97-15 This integrated inspection included aspects of licensee operations, engineer.
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inn, maintenance, and plant support.
The report covers a six week period of l
l resident and region based inspection, in addition, this report includes the i
findings from an August 22. 1997, review of the 1996 revision to the McGuire Updated Final Safety Analysis Report.
Operations Operator performance following the loss of non safety 120 volt alternating current panelboard KXA and the subsequent dual unit trip was generally adequate.
However, operations' failure to execute Technical Specification required actions regarding pressurizer power operated relief valves operation and inoperable radiation monitors were identifiedasNon-QitedViolations.
Problems were also identified concerning o tria and the,perator cognizance of plant equipment operating during the status of associated system parameters.
A significant wea(ness was identified concerning the failure of the licensee to
. recognize Unit I auxiliarygfeedwater pump operation below minimum recirculation flows prior ty unit restart.
The lack of preventive maintennce activities for nonsafety related components was a direct contributor to the event.
(Section 02.1)
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Inspectors * observations of planned Nuclear Safety Review Board meetings
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concluded that the Nuclear Safety Review Board was providing good oversight of the facilities * operation.
(Section 07.1)
Maintenance Branch welding of main feedwater pipe assemblies was progressing in a
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satisfactory manner.
Rejection rates were declining as welders were responding to training and gaining more confidence with equipment, materials and welding processes used.
(Section M1.2)
The licensee was providing well-qualified engineering and technical
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personrel to support and monitor the ongoing investigation and possible repairs of a nonconforming condition in the replacement steam generators.
(Section M1.3)
A review of repair records associated with problems welding the Unit i
high pressure turbine blade ring locating pin, disclosed that the weld procedure selected for the weld repair was not qualified for the application. The licensee identified the weld failure as a Maintenance Preventable Functional Failure.
The root cause was attributed to poor weld quality.
(Section M1.4)
Enclosure 2
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The ins)ectors concluded that the licensee's identification of moisture
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in the ) nit 1 turbine driven auxiliary feedwater pump local control panel waa good.
Corrective actions taken for the degraded condition were appropriate.
At the end of the inspection period, the licensee was continuing to evaluate other potential corrective actions to preclude future events.
(Section M2.1)
The licensee's response to the lubrication on reactor trip breaker
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current carrying surfaces was good.
Detailed testing and follow up by engineering and maintenance teams was evident. The removal of the graphite lubricant was a conservative action to ensure operability of the solid state protection system.
(Section M4.1)
A procedure adherence violation was identified involving a failure to
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identify and remove from service a steam generator tube with a rejectable indication in Unit 2A steam generator. A tube leak occurred and caused an unplanned shutdown.
Also, the licensee identified the
leak as a maintenapte preventable functional failure.
(Section M8.1)
Enoineerina
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. A Non Cited Violation was-identified for the licensee's failure to
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evaluate the suitability of,the high efficiency particulate air filters prior to installing them in'the Unit 1 and Unit 2 reactor buildings.
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The failure indicated a significant loss of cpntrol in preventing undesirable material in the reactor buildino.
(Section E2.1)
In general, the 1996 revision of the McGuire Updated Final Safety
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Analysis Report met the provisions of 10 CFR 50.71 and is therefore, cur rently in compliance with 10 CFR 50.71.
An Inspector Follow up Item was identified to review a reduction in Updated Final Safety Analysis Report drawing detail.
Discrepancies identified concerning earlier revisions were incorporated into a previously existing Unresolved item.
(Section E3.1)
No immediate safety issues existed for the potentially degraded spent
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fuel pool Region 1 Boraflex condition concerning boron densities below
- riticality 3nalysis assumptions.
The licensee's evaluation was prompt and proposed actions to develop more restrictive fuel loading limits were appropriate to ensure that adequate criticality safety margins will be maintained.
(Section E4.1)
The licensee's evaluation of the emergency sump inventory issue recently
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identified at anotner ice condenser facility was good.
The issue was determined to not be a concern at the McGui.e facility.
(Section E7.1)
Enclosure 2
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Plant Sunnort The licensee had effectively im)lemented a program for shipping
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radioactive materials required )y the NRC and Department Of Transportation regulations.
(Section RI.1)
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Report Details
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Summary of Plant Status l
Unit 1 Unit 1 began the inspection period at approximately 100 percent power. On September 6. the Unit 1 reactor automatically tripped on a main turbine trip
i above the P-8 permissive following a loss of both main feedwater (MFW) pumps.
The MFW pump trips occurred as a result cf the loss of non-safety power
)anel board XXA, The supply side breaker to KXA tripped on thermal overload w111e in a temporary configuration to allow preventative maintenance on the KXA normal- )ower supply. The licensee identified a loose connection as the cause of the areaker tripping.
Following the reactor trip, steam dump control was lost since Unit I steam dump control was powered by KXA.
Steam was released through the steam generator power operated relief valves (PORVs) and code safety valves.
Additional problems are identified in Section 02.1.
Unit I was restarted and aligned to the electrical grid on Se)tember 9,1997.
The unit operated at approximately 100 percent power for tie remainder of the inspection period.
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Unit 2 Unit.2 began the inspection pe'rjqd at approximately 100 percent power. On September 6. the Unit 2 reactor automatically tripped on high pressurizer pressure following the loss of non safety power panelboard KXA. The Unit 2 trip occurred simultaneously with the Unit 1 trip,following the reactor trip. Unit 2 primary system pressure increased after all four main steam isolation valves closed due to being powered by the KXA bus.
The reduction in primary system heat removal resulted in a pressure increase to approximately 2385 psig.
Pressurizer PORVs did not automatically operate to relieve system pressure since panelboard KXA also provided control power for PORV automatic control, as well as 2A main feedwater (MFW) pump speed control. Other problems are identified in Section 02.1.
Unit 2 was subsequently restarted and aligned to the electrical grid on Seatember 10. 1997.
The unit operated at approximately 100 percent power for t1e remainder of the inspection period.
Review of Undated Final Safety Analysis Reoort (UFSAR) Commitments While performing inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that were related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and/or parameters.
Related concerns are addressed in Section E3.1.
Enclosure 2
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1. Operations
Conduct of Operations 01.1 General Comments (7170]l
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Using Inspection Procedure 71707. the inspectors conducted frequent
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reviews of ongoing plant operations, in general the corduct of l
oaerations was professional and safety conscious.
Operators were l
clallenged during the period due to the dual unit reactor trip. and generally responded well.
However, several instances were identified where operator ccanizance of operational parameters and ecuipment status l
Tollowing the reactor trip events could have been im)rovec.
Specific events and noteworthy observations are detailed in t1e sections which l
follow.
01.2 10 CFR 50.72 Notifications
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a.
Insnection Stone During the inspection seriod, the licensee made the following
. notifications to the NRC..iThe inspectors reviewed the events for impact ontheoperationalstatusofthefacilityandequipment, b.
Observations and Findinas f
On September 6. the licensee made notification of dual unit
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reactor trias following the loss of 120 volt alternating current (VAC) panel)oard KXA.
The apparent cause of the )ower loss was identified as a loose connection on the breaker w11ch caused the KXA supply breaker to open on thermal overload.
The licensee plans to submit a licensee event report (LER) on the event.
On September 9. the licensee notified the NRC of a failure to
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comply with Technical Specification (TS) requirements for inoperable pressurizer PORVs. The licensee failed to meet the requirements for the inoperability of three PORVs as specified in TS 3.4.4.d.
This issue is further discussed in Section 02.1.
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Conclusions The inspectors concluded that the licensee reported the above events in accordance with the requirements of 10 CFR 50.72.
Enclosure 2
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02-Operational Status of Facilities and Equipment
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02.1 Dual Unit Reactor Trio. loss of Shared Non Sa 'ety 120VAC Power Supoly L
a.
Insoection Scone (71707.93702)
On September 6. McGuire Unit 1 and Unit 2 automatically tripped following the unexpected loss of power to 120 VAC power panelboard KXA.
Control power was lost to several components and control room indications on both units. As a result of-the power loss. the Unit I reactor automatically triaped following a turbine trip. Unit 2 automatically tripped on ligh pressurizer pressure.
The inspectors responded to the plant-and evaluated licensee and equipment performance, b.
Observations and Findinas
__ Backaround Prior to the loss 6f power to panelboard KXA and the subsequent automatic reactor trips. Units 1 and 2 were generating at 100 percent
)ower. The shared 125 so't direct current-(VDC) control power system
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. )attery.CXA and associated 0tatic inverter had been isolated from the normal distribution center QCA while battery CXA was equalized following annual battery service testing.
Consequently,
)anelboard KXA was
)owered from the alternate source MKA.
During Jattery equalization, no
)attery or other backup power supplies were available to power panelboard KXA, This operational condition (no battery backup) is only entered during the annual battery reventive maintenance (PM).
The licensee determined that the suppl breaker from the alternate power source (MKA) tripped due to heat b ildu) created by a loose cable connection on the load side of the breater, actuating the thermal trip units and de-energizing panelboard KXA. The licensee previously made a decision not to perform preventive maintenance on ii!s and other associated KXA breakers due to the system electrical design which requires the KXA bus for operation of both units.
Numerous control functions and indications were disabled, which affected both units and resulted in the reactor trips.
After the event, the inspector was informed that a similar event had previously occurred on September 6.1987 which was reported in LER 370/87 16. Revision 1.
During the arevious event, a loss of power to power panelboccd KXB resulted in a Jnit 2 reactor trip.
Unit I was shutdown at the time. As with the current event, the ioss of KXB was coincident with the licensee's performance of an ar..iual PM on the battary backup power supply to the affected power panelboard.
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Event Descriotion On Unit 1..the loss of KXA caused both MFW pumps to trip.
The loss of MFW caused an automatic turbine trip and automatic start of the motor Enclosure 2
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l driven auxiliary feedwater (MDAFW) pumps.
The loss of panelboard KXA caused the turbine driven auxiliary feedwater (TDAFW) pump steam supply valves to open, resulting in pump operation.
The turbine trip resulted in an automatic reactor tri a from 100 percent power.
Main condenser steam dump control was disa) led following the loss of power to KXA:
therefore, steam pressure was relieved to the atmosphere through steam generator PORVs and code safeties. Steam generator PORVs were used by operators to adequately control steam pressure. After power was restored to panelboard KXA (a little more than one hour after the reactor trip). steam dump control was regained.
Pressurizer )ressure increased to approximately 2366 psig. Automatic pressurizer 30RV operation was disabled by the loss of KXA.
Pressurizer pressure did not reach code safety set points.
Manual pressurizer operation was available to operators throughout the event.
On Unit 2. de energizing panelboard KXA caused all four main steam isolation valves to close.
Primary system temperature and pressure increased due to the loss of heat removal. Automatic pressurizer PORV control was also irioperable due to the loss of KXA.
Unit 2 automaticalYy tripped when pressurizer pressure reached the high pressure reactor trip se,t point cf 2385 psig No pressurizer code
.safetieswerechallenged..@teamganeratorPORVsandcodesafeties cycledtocontrolsteampregsure. The TDAFW pump was manually started to maintain steam generator levels.
Steam generator PORVs continued to cycle to control steam pressure until the mair steam isolation valves were re-opened following the restoration of po)wer to panelboard KXA.
Personnel and Eauioment Performance The inspectors responded to the control room and observed personnel and equipment performance. After power was restored to KXA. both units were stabilized in Mode 3. with all primary and secondary plant parameters within expected ranges. The inspector noted that the operating crew was adequately staffed (exceeded TS minimum requirements) and had been successful in identifying and correcting the apparent cause for um m
of XXA early in the event.
In general, operator response to the reactor trips was adequate, considering the loss of numerous control functions and control room indications that were normally supplied by KXA.
However, several problems were identified by the licensee concerning operator actions during the transient. Specifically, operators " ailed to execute the requirements of TS 3.4.4. Action d. and TS 3.3.31.
TS 3.4.4. Action d specifies that with three pressurizer PORVs incperable for causes other than excessive leakage, within one hour either restore at least one PORV to operable status ce close and remove power from the associa:ed block valves, be in Mode 3 (Hot Standby) within the next six hours, and in Mode 4 (Hot Shutdown) in the following six hours.
TS 3.3.3.1 specifies that with either of the control room air intake radioactivity high monitors inoperable. Bolate the control room ventilation system outside air intake that contains the inoperable Enclosure 2
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radioactivity monitor within one hour.
Neither action was executed within the specified time constraints. These failures each constitute a violation of minor significance and are being treated as Non-Cited Violations (NCV) consistent with Section IV of the NRC Enforcement Policy.
NCV 50-369.370/97-15 03: Failure to Implement the Requirements of TS 3.4.4 and NCV 50-369.370/97-15 04:
Failure to Implement the Requirements of TS 3.3.3.1.
In addition to the above, the inspectors identified a weakness in the operators' cognizance of key operating equipment imr$diately after the event.
Specifically, the Unit 1 operators did not immediately recognize that the IDAFW pump was running.
At approximately 20 minutes after l
event initiation, operators reduced SG flow by closing the MDAFW pumps flow control valves.
Operators then recognized that additional flow to
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the SGs was from the TDAFW pump and took actions to close its flow control valves.
The initial actuation of the TDAFW pump and closure of all the AFW pumas' recirculation valves (discussed below) were not recognized by t1e operators.
Adeauacv_of' Post-Trio Review
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. Prior to restart of voth' units. a post-trip investigation was aerformed as directed by Nuclear System Directive 505. Investigation of Reactor Trips using PT/0/A/4700/45.* Reactor Trip Investigation. The inspectors attended the post trip restart Plant Operatiogs Review Committee (PORC)
meeting.
In general, the restart review teag had adequately determined the cause of the dual unit reactor trias and associated equipment performance as previously discussed.
h ever. no issues were specifically identified or discussed concerning auxiliary feedwater (AFW) system performance.
Following the restart of both units, the licensee recognized that the Unit 1 auxiliary feedwater pump minimum flow recirculation valves had closed on the loss of sower panelboard KXA. thereby resulting in dead-heading the pumps. Tus had not been recognized by the restart team.
This oversight occurred due to the post trip review team not reviewing a complete list of operational loads that were de-energized upon the loss of KXA, The inspectors noted that the closure of the AFW pumps' recirculation flow valves was not apparent to the o)erators although main control room panel indicators identify panelJoard KXA as the power su) ply.
This was an additional opportunity to identify the AFW aump dead-leading issue prior to restart. The licensee concluaed tlat once control of steam generator levels was regained following the Unit I trip. operators had reduced feedwater flow to the generators causing the AFW pumps to operate under adverse flow conditions for 20 to 60 minutes by the licensee's estimates.
Upon restoration of panelboard KXA, the AFW pump recirculation control valves end Unit 1 TDAFW pump steam supply valves returned to their proper positions. The failure of the post-trip review team and other restart assessments to identify AFW pump operation below minimum recirculation flows is identified as a significant weakness.
Enclosure 2
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U)on identification of the potential dead heading of the three Unit 1 l
A;W pumps, operability runs were conducted to verify pump performance in accordance PT/1/A/4252/01B. Auxiliary feedwater Pump Testing.
No flow or vibrational degradation was noted, when compared to previous AFW pump test performance data.
Based on previous data regarding SG control valve leakage, the licensee concluded that tne AFW pumps did not i
l experience complete shutoff flow conditions.
In addition the licensee l
consulted with the AFW oump vendor regarding the reduced flow conditions
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experienced by the pumps and performed a thermal analysis estimate of the pump conditions.
This analysis concluded that the conditions experienced by the Unit 1 AFW pumps would not have impacted the current operability of the pumps.
At the end of the inspection period, the l
licensee was continuing to evaluate the long term actions associated with this AFW pump event.
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Conclusions l
The inspectors evaluated licensee and equipment performance following the dual unit trip,' Operator performance was generally adequate.
However, opdrations' failure to execute TS required actions regarding pressurizer PORV operatian and inoperable radiation monitors were
, identified as NCVs.
Prodeps were also identified concerning operator cognizance of plant operating equipment and the status of associated system parameters. A significant weakness was identified concerning the failure of the licensee to recognize Unit 1 AEW pump o>eration below minimum recirculation flows prior to unit redart.
T1e inspectors also concluded that the lack of preventive maintenance activities for nonsafety-related components was a direct contributor to the event.
Quality Assurance in Operations 07.1 Nuclear Safety Review Board (NSRB) (40500)
a.
Insoection Scoce On September 18, 1997, the inspectors attended the McGuire NSRB meeting held at the Catawba site.
b.
Observations and Firdinas Site presentations to the board included plant performance, reportable events, violations, trends, areas for improvement and other relative issues. The inspectors considered that the information NSRB gave a realistic view of overall plant performance. presented to the The inspectors found the NSRB to be candid. providing good safety oversight input to the plant.
Numerous proposals for improved performance were suggested and documented for resolution.
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Conclusioni ins)ectors' observations of planned NSRB meetings concluded that the NSR3 was providing good oversight of the facilities' operation.
Hiscellaneous Operations Issues (92700)
08.1 (Closed) LER 50 369/96-05:
Technical Specification Required Shutdown of Both Units Due to a Failed Surveillance Test of Vital Battery EVCC Caused by an Unknown The inspectors evaluated the licensee's corrective actions and determined that the actions had been completed within the licensee's l
i established time frame.
The AT&T Lineage 2000 batteries have been replaced and the replacement batteries have been satisfactorily tested to ensure reliable operation.
Therefore. LER 50-369/96 05 is closed.
- II. Maintenance
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M1 Conduct of Maintenance.
M1.1' General Comments (61726 and 62707)
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a.
Insoection Scooe
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The inspectors observed all or portions of the following work activities:
PT/1/A/4350/02A 1A Emergency Diesel Generator Operability Test PT/2/A/4208/01A Containment Spray Pump 2A Performance Test PT/1/A/4403/01A Nuclear Service Water Pump 1A Performance Test WO 96080906 Load Test Steam Generator Support Trestle b.
Observations and Findinas The inspectors witnessed the selected surveillance tests to verify that approved procedures were available and in use: test equipment in use was calibrated; test prerequisites were met: system restoration was completed: and acceptance' criteria were met.
In addition, the inspectors reviewed and/or witnessed routine maintenance activities to verify. where applicable that approved procedures were available and in use: prerequisites were met: equipment restoration was completed; and maintenance results were adequate.
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Conclusion
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The inspectors concluded that these routine activities were completed satisfactorily.
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M1.2 Unit 2 Steam Generator Replacement (SGR)
a.
Insoection Scone (50001)
The inspector observed and evaluated the adequacy of in p's weld rogress welding of main feedwater (CF) piping assemblies at the licensee
fabrication facility (fab shop).
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b.
Observations and Findinas At the time of this inspection. CF pipe assemblies were being
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fabricated. A)plicable codes included American Society of Mechanical
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Engineers (ASM D. Sections XI. 1989 Edition and Section III. 1971 Edition.
Walds selected at random for observation and review of process control records were as follows:
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'.61Ie Remarks CF2FW62-20 18"x 0.844" Tacked in preparation for welding out joint.
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CF2FW62-21 18"x 0.844"
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CF2FW62-25 18"x 0.844" Completed and prepared for radiography.
d CF2FW62-26 18"x 0.844" Completed and prepared for
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radiography.
CF2FW63-08 18"x 0.938" Tacked in preparation for welding out joint.
CF2FW63-17 16"x 0.844" Completed and prepared for radiography.
For the above welds, the inspector checked weld root and reinforcement for compliance to code requirements, including root gap, alignment, cleanliness and weld identification.
Completed welds were checked for root condition (i.e.. excessive concavity, smooth transition and blending).
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Process control records were reviewed for completeness and accuracy.
Quality records for filler metal and welder qualification were reviewed and found to be satisfactory.
Discussions with the cognizant welding Enclosure 2
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engineer and a review of weld fabrication history logs revealed that the licensee was making good progress in improving weld quality and reducing rejection rates. Training of welders on mock-ups was used more frecuently as a means of preparing for welding difficult. off position t
welcs. Welders had become more familiar with automatic welding machines. These machines were now being used more frequently to fabricate welds, resulting in relatively good results, l
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Conclusions
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in general, the welding program in place for this SGR was moving in a positive direction. The need for repeat weld repairs per joint was trending downward. This downward trend eppeared to be the result of
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improved welder training, attention to details and a proactive weld support group that closely follows this activity.
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M1.3 Qff-Desian Condition in Babcock Wilcox International (BWI) Reolacement SG(s) (Unit 2)
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a.
Insoectionscope(%01)
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. The inspector inspected tbet b bend outer periphery tubes in SG D to observe a less than optimum; radial gap condition between certain
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outermost tubes and adjacent tubes.
This condition was identified by
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BW1 during inspection of another utility's replacement SGs.
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b.
Observation and Findinas This inspection-effort was performed in response to BWl's information bulletin titled."U-bend Tube Spacing", dated August 28. 1997. The subject bulletin disclosed that an inspection of a SG U bend assembly under fabrication, revealed that the spacing between certain outermost tubes and the adjacent tubes immediately beneath them was less then optimum. The concern was that the less than optimum radial gap between adjacent tubes could result in increased wear during operation and diminish the service life of the subject tubes. The inspector, accompanied by the licensee's cognizant engineer and the vendor, observed the U bend region of the tube bundle in SG D.
The inspector observed a sample of the affected tubes and noted the difference in spacing between acceptable radial gaps and those identified as less than optimum.
The= licensee had retrieved and examined baseline eddy-current test (ET)
data which showed that SG D had approximately 44 tubes exhibiting this condition.
The subject visual ins)ection at the specific tube locations confirmed this condition. After t11s confirmation. BWI and the licensee were collecting data and discussing their options for resolving the problem. These options included cutting, and rewelding the J-tabs to the U-bend support assembly or plugging the effected tubes.
BWI Enclosure 2
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initiated an evaluation to determine whether the problem qualified as a 10 CFR Part 21 item, c.
Conclusions The licensee had taken a proactive role in the inspection. investigation and dispositioning process by providing well-qualified and knowledgeable engineers to monitor and review BWl's corrective actions.
M1.4 Hiah Pressure (HP) Turbine Blade Rina locatina Pin Weld Defects (Unit 1)
a.
Insoection Scoce (62700)
Determined by document review and discussion;. the root cause of problems associated with welding the HP turbine blade ring locating pin to the blade ring.
b.
Observation and Findinas
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Discussions 'with the licensee's cognizant welding engineer confirmed that the licensee had e@erienced repeated weld failures in his attempts
. to weld the HP blade ring.to the' locating pin. A root cause analysis revealedthatthisweldfai]urewasduetopoorWeldqualityandwas identified as a MPFF.
(For further details see Section M2.2 of Inspection Report 50-370/97-09.) This problerp was identified in Problem it.vestigation Process (PIP) re) orts 1-M97-2160 and 1 M97-2241. The inspector's review disclosed tlat the Field Weld Data Sheet (FWDS) L-370. Rev. 1. Shield Metal Arc Welding, that was selected to perform the blade ring to pin seal weld had not been qualified for the welding electrode used to make the subject weld and was probably a contributing factor.
The licensee issued PIP report 1-M97-2961 and qualified a new weld procedure (L 300) using the correct welding electrode. The inspector reviewed the new weld procedure cualification record and found it to be satisfactory.
The inspector notec that the problem weld was re welded using E-7018 filler metal which provided for better ductility and ease of welding.
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Conclusions The root cause of this problem was attributed to poor weld quality and a lack of attention to details.
H2 Maintenance and Haterial Condition of Facilities and Equipment M2.1 AFW Operability a.
Inspection Scoce (62707)
The insnectors evaluated the licensee's response to identification of moisture in the turbine driven auxiliary feedwater pump control panel.
Enclosure 2
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The turbine driven auxiliary feedwater pump control panel is used during
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loss of control room events.
b'.
Observations and Findinas On August 18 the licensee noted moisture accumulation near the base of the Unit 1 turbine driven auxiliary feedwater pump local control panel.
The licensee initiated investigations and determined that the water at the base of the panel had leaked out of the control panel. A nonsafety-related pressure switch diaphragm had failed and the resulting pressurization of the housing forced water through the associated cable-sleeve-into the control panel. Water collected within the control panel and subsequently migrated to the exterior floor.
No indication of wetting of the safety grade components was identified. Because the
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panel was designed to be a watertight flood barrier to protect against i
an auxiliary feedwater pipe rupture, the panel was declared inoperable-and work order 97072024 was initiated to repair the degraded seal. Work
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order 97072077 was, completed to replace the failed pressure switch.
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The licensee' performed an operability review to evaluate the impact-of pipe breaks within the auxiliary feedwater pump rooms, control cabinet flood barrier seals, and the impact that the moisture intrusion may have
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had on safety-related components inside the control panel. The inspectors reviewed the licensee's evaluation and noted that although the water level within the control panel was within acceptable ranges.
water intrusion may have complicated plant operation during a pipe rupture at unit startup.
c.
Conclusion The ins)ectors concluded that the licensee's identification of moisture in the Jnit 1 turbine driven auxiliary feedwater pump local control panel was good.
Corrective actions taken for the degraded condition were appropriate. At the end of the inspection. period, the licensee was continuing to evaluate other potential corrective actions to preclude future events.
H4 Maintenance Staff Knowledge and Performance M4.1 Solid State Protection System (SSPS) Testino - Reactor Trio Breaker 2B_YA a.
Insoection Scoce (61726)
The inspectors evaluated the licensee's findings and response to higher than expected resistance indications during testing of SSPS logic.
circuitry; Enclosure 2
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!
_ - -.
.
..
- _ - -.
-
..
.- -
--.
- - -
..
.
.
b.
Observations and Findinas During the performance of PT/0/A/4601/08A. Train A SSPS Periodic Test, the licensee identified higher than expected resistances on the P-4 Turbine Trip contact on 0S-416 bypass reactor trip breaker. 2BYA.
A similar issue was identified in February 1997 during SSPS testing.
The licensee recognized that higher resistance values on other trip breaker contacts could potentially result in an inability to reset a safety injection (SI) signal and adversely affect operator performance during certain accident scenarios.
The resistance values measured across the contacts di'J not comply with vendor recommended values. The licensee declared the 2BYA breaker inoperable. Since the normal Unit 2 reactor trip breaker (2RTA) was in service, no immediate corrective actions were necessary. The SSPS Train A was considered operable.
The licensee stated that the cause for the higher resistance values were excessive amounts of vendor recommended graphite lubricant (Westinghouse 53701AN).
The excessive lubricant ap) lied to the current carrying surfaces prevented good cont,1nuity Jetween the fixed and movable contact surfaces.
,
The licensee cleaned the. contacts and implemented emergency work
. requests to clean and lubni,cate the auxiliary switch contacts on all installed reactor trip breahers in accordance with the revised procedures to provide added assurance of trip breaker performance.
The contact resistance values were verified to be,within acceptable ranges.
The licensee contacted Westinghouse for additional technical support to evaluate a minor modification to amend the Westinghouse Manual for DS-416 breakers to delete the requirement to apply graphite grease to the auxiliary contact and remove the associated references. Westinghouse approved the removal of the requirements to lubricate the auxiliary switch contacts in a letter to the licensee dated August 28. 1997.
The letter stated that the removal of the lubricant was acceptable: however.
Westinghouse Electric Corporation recommended that new switches be installed. maintained in accordance with recommended breaker maintenance intervals. and replaced at 500 cycles or less, c.
.ConclusioD1 The ins)ectors concluded that the licensee's res)onse to the lubrication on brea a r current carrying surfaces was good.
Jetailed testing and followup Dy engineering and maintenance teams was evident.
The removal of the graphite lubricant was a conservative action to ensure opcrability of the SSPS system.
Enclosure 2
.
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_.
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _
__
_
.
.
M8 Miscellaneous Maintenance Issues (o 12)
M8.1 (Closed) Unresolved item (URI) So
/0/97-09-02: Steam Generator Inspection Process This item was identified in res)onse to the licensee's 'ailure to evaluate an indication in tube 17C60 of SG 2 during the 10th Unit 2 refueling outage in April 1996.
The tube failed on June 14. 1997, and the plant was forced into an unplanned outage to perform re) airs. The licensee evaluated the tube failure and identified it as c 4PFF.
At the
'
close of this inspection the licensee was in the process of completing a root cause investigation to focus in on the problem and implement appropriate corrective measures to prevent a recurrence of similar problems. The inspector reviewed PIP 2-M97-2382 and other related documents provicted by the licensee and held discussions with the
,
cognizant engineers. The licensee's review of ET data from the last l
outage. (end-of-cycle 10) on the subject tube disclosed that the indication was located at the 21st tube su) port plate plus 5.2 inches.
The indication had'been identified with a Jobb1n coil, characterized as a non-quanti'fiable indication (Ldl) and measured approximately 2.68 volts.
On or about April 20, 1996, results of the motorized pancake
. coil (MRPC) examination weqe reviewed by primary and secondary analy.ts l
who determined that the signal was too noisy to evaluate and requested a l
re examination of the location of interest.
However, in doing so, the
'
acquisition crew failed to follow ET Analysis, Guidelines. Ap)endix C recuirements which require that the MRPC exarpination cover t1e incication d " (two inches).
Instead of inspecting the tube indication within the prescribed tolerance. a review of the re-examination results show that data acquisition had examined a distance of -5 inches. +1 inch.
Btth independent analysts, primary and secondary, who analyzed the MRPC data, agreed on the finding and coded the data as " Retest-Incomplete (RIC)".
This code entr.) required a re-examination because the previous excmination did not meet the 2" criterion.
However, before performing the re-examination, the resolution analyst who reviewed the data changed the code entry to "No Defect Found (NDF)."
This resolution indicated that no defect was confirmed and resulted in the tube being returned to service instead of being plugged.
In reference to this review, the aforementioned guidelines state that the
.
resolution analyst will review ET data to resolve discrepancies between the primary and secondary analysts.
Hr.-tever in this case, the data disclosed that both arimary and secondary analysts were in agreement in requesting an RIC: t1erefore, no discrepancy was involved.
These two failures to follow ET Analysis Guidelines dated March 27. 1996, were identified as two examples of a violation (VIO) of TS 6.8.1 and will be identified as VIO 50-370/97-15-01:
Failure to Follow ET Analysis Guidelines.
The previously identified URI 50-370/9'/-09-02: Steam Generator Inspection Process, was closed.
Enclosure 2
<
. _ _, _ _ - _ _ _ _
.
.
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III. Ennineerina-E2 Engineering Support of Facilities and Equipment E2.1 Containment Purae Filtration Aluminum Content a.
Insoection Scoce (37551)
l The inspectors evaluated the licensee's quantification of aluminum in
'
the Unit 1 and Unit 2 reactor buildings. The evaluation focused on the licensee's calculation of hydrogen concentrations during design basis'
!
events which result in individual heat removal system operation in the recirculation mode of core cooling, b.
Observations and Findinas On AugJst-6. the licensee determined that the quantity of aluminum in
the Urit 1 and Unit 2 reactor buildings exceeded allowable values I
s)ec.fied in the McGuire Updated Final Safety Analysis Report (UFSAR).
T1e increase was due to installation of replacement high efficiency
.
particulate air (HEPA) and prefilters used in the Containment Purge
'
. System lower containment hltration units. The replacement filters.
g'
installed in 1991, incorporgted aluminum separators to provide
-
additional structural strength. The maximum total allowable inventory of aluminum had been quantified in the UFSAR pt 433 square feet.
Conservatively, the McGuire UFSAR Table 6-117 used 1500 square feet in the hydrogen generation analysis to account'for future aluminum additions to the containment.
The inspectors reviewed the Unit 1 and Unit 2 McGuire Aluminum Inventory Insiae Containment Calculations. MCC-1223.02 00-0013 and MCC-2234.02-00-0001.
The inspector also reviewed MCC-1552.08-00-0057. Reanalysis of Hydrogen Skimmer System Flow Requirements.
The calculations were
.'
performed to quantify the amount of aluminum in the reactor buildings and verify that the hydrogen skimmer s stem flow requirements were adequate to mainta1n reactor bui' ding ydrogen concentrations less than
>
4 volume percent.
The total aluminum nventory for Unit I was 14,148 and 14.130 for Unit 2.
The replacement filters alone accounted for approximately 13.186 square feet.
The hydrogen generation analysis assumed 14.250 square feet to account for the additional inventory of alumir.um.
The licensee's calculations concluded that complete consum3 tion of the newly discovered aluminum within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> would not cause lydrogen concentration to exceed 4 percent by volume prior to recombiner operation and the newly recognized. total inventory of 14.250 square feet does not cause hydrogen concentration to exceed 4 volume percent over 30 days post-LOCA.
Enclosure 2
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.
c.
Conclusions Although the increase in the amount of aluminum was determined to be acceptable, the licensee removed the filters from the Unit 1 containrent purge system and has stated that the filters located in the Unit 2 Containment Purge System will be removed during the next scheduled refueling outage.
The inspectors reviewed the issue for regulatory significance and concluded that the licensee failed to evaluate the suitability of the filters prior to installing them in the reactor building. This failure was a violation of 10 CFR 50 Appendix B Criterion III. Design Control.
Because of the licensee's corrective
,
actions to remove the material from the Unit 1 and Unit 2 reactor i
buildings and the proposed actions to prevent recurrence, discretion was exercised.
However, the inspectors concluded that the failure indicated
'
a significant loss of control in preventing undesirable material in the reactor building.
Although the as found condition was acceptable this
!
oversight for an extended period of time, was considered significant.
This non-repetitive, licensee-identified and corrected violation is being treated as a'Non-Cited Violation, consistent with Section Vll.B.1 I
of the NRC Enforcement Policy. NCV 50-369.370/97-15-02: Failure to Evaluate Material Suitab,ility With Respect To Aluminum in Reactor
. Building.
E3 Engineering Procedures and Documentation E3.1 1996 Revision to the UFSAR
/
a.
Insoection Stone (37551.).
The inspectors reviewed the 1996 revision of the McGuire UFSAR in-office and met with licensee personnel on-site during a meeting (see NRC meeting summary dated August 22. 1997).
By letter dated November 6.1996, the '9ame submitted the 1996 revision to the UFSAR in accordance wn.
. CFR 50.71.
This regulation requires that this submittal shall contain all the changes necessary to reflect information and analyses submitted to the Commission by the licensee or arepared by the licensee oursuant to Commission requirement since the su) mission of the or'ginal SAR or, as appropriate, the last updated FSAR...and revisions r St reflect all changes up to a maximum of six months prior to the date cf filing.
Section 50.71 provides that the UFSAR shall be revised to include the effects of:
"All changes made in the facility or procedures as described in
.
the FSAR."
" Safety evaluations performed by the licensee either in support of
.
requested license amendments..." - Since this category clearly Enclosure 2
.
.
involves NRC staff approval of licens' i changes that the staff approved (e.g., g basis changes, other topical reports, reliefs to ASME Code sections exemptions. etc.) but were not conveyed as amendments are also implied.'
"...or in support of conclusions that changes did not involve an unreviewed safety question" - These are evaluations performed by
{
the licensee in accordance with the provisions of 10 CFR 50.59.'
!
"All analyses of new safety issues performed by or on behalf of
.
the licensee at Commission request" - Examples include licensee
,
l actions as a result of generic letters bulletins, etc."
~
The regulation does not require that the NRC staff has to review and approve the changes in the UFSAR. since the changes are presumably previously approved or do nnt require ap3roval. Accordingly, the purpose of t1e review was to confirm if t1e changes made in the 1996 revision comply with the provisions of 10 CFR 50.71.
l b.
Observations'and Findinas l
. The inspectors traced th'e changes in the 1996 revision of the UFSAR to I
documents in the official NRC records (amendments to the operating license, staff letters transmitting safety evaluations, annual 10 CFR 50.59 reports submitted by the licensee inspection reports, licensee letters, etc.).
The inspectors confirmed thqf the 1996 revision does not constitute a source of initial communication of these changes.
The inspector noted that certain plant systems described in the UFSAR were modified by the licensee in 1991 and 1992, but the UFSAR did not reflect the changes until 1996.
The )lant modifications in 1991 and 1992 included removing or disabling t1e upper Head Injection System and changes to the Containment Pressure Control System air return fan and discharge dampers.
Both these systems were described in the FSAR. yet the UFSAR did not get changed until 1996. These changes in the UFSAR should have been in an earlier revised filing.
Section 50.71(e)(4)
requires that revisions must reflect all changes up to a maximum of six months prior to the date of filing. This UFSAR discrepancy will be identified as additional examples of URI 50-369.370/96-04-02. UFSAR Discrepancies. Their significance will be evaluated further during closecut of the URI.
The inspectors also noted that the licensee revised site drawings in the UFSAR into summary one-line flow diagrams (for example. Figures 9-58, 9-59. 9-60. 9-61. 9-62. 9-6. 9-93. 10-30).
At the end of the inspection period. it was not clear whether creating these summary diagrams of UFSAR drawings leads to a reduction in previously agreed upon information or changing previous commitments or both.
The inspectors concluded that further review on this issue was required to determine if the licensee's actions during drawing revisions were Enclosure 2
_. _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _
.
,
,
<
ap3ropriate. This issue will be identified as Inspector Follow up Item
!
(I:I) 369.370/97 15-05. Reduction of UFSAR Orawing Detail
'
i As a result of the licensee's pilot UFSAR review, the licensee concluded i
that the UFSAR lacked accuracy and completeness.
Currently. the
licensee is in process of conducting a UFSAR review to determine the extent of problems with the UFSAR.
c.
Conclusion
In general, the 1996 revision of the McGuire UFSAR met the provisions of
-10 CFR 50.71 and is therefore, currently in compliance with 10 CFR t
50.71. An Inspector Follow up Item was identified to review a reduction i
in UFSAR drawing detail.
Discrepancies identified concerning earlier
UFSAR revisions were incorporated into a previously existing Unresolved Item, E4 -
Engineering Staff Knowledge and Performance E4.1 Dearaded Bor/aflex in Soent Fuel Racks a..InsoectionStone(37551f.3 l
The inspectors evaluated thd licensee's immediate corrective actions for i
coping with potentially degraded neutron absorbing material Boraflex in the Unit 1 and Unit 2 spent-fuel pools (SFPs f. The inspectors discussed
'
the issue with reactor engineering personnel and reviewed the original license amendment approving use of the spent fuel racks and the McGuire
'
b.
Observations and Findinas On September 9,1997, the licensee identified a potential non-conservative-TS with regard to storage of spent fuel in the Unit 1 SFP storage racks. Specifically. TS 3.9.13 is )otentially inadequate to -
ensure the criticality design criterion of-q3.less than 0.95 is-
,
satisfied.
The values contained in TS Table 9-1. Minimum Qualifying Burnup Versus Initial Enrichment for Unrestricted Region I Storage, and Table 3.9 2. Minimum Qualifying Burnup Versus Initial Enrichment for-Region I Filler Assemblies, may need to be more restrictive.
Region I of the SFP is designed for storage of fresh'or partially irradiated fuel.
The licensee discovered the condition when preliminary results of testing that was performed on the Unit 2 Boraflex earlier this year revealed that boron-10 areal densities were below the criticality analysis assumption of 0.02 grams B-10/ square centimeter.- This testing
,
was performed in response to NRC Generic Letter 96-04. Boraflex-
Degradation in Spent Fuel Pool Storage. The testing of Region 11 racks revealed that the racks were above their analysis assumption of 0.006 Enclosure 2
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_ _ _ -
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1B grams B-10/scuare centimeter.
The licensee also believes that the testing and cata for Unit 2 racks are directly applicable to Unit 1 since the racks are identical in design.
No immediate safety issues were identified since:
The present fuel loading configuration in Region 1 of the SF"s
.
(approximately only one assembly in Region I) meet limiting requirements.
l Criticality calculations do not take credit for soluble boron.
.
The licensee stated that with present concentrations (2475 ppm)
'
k,,, of less than 0.95 would be maintained even if no B-10 were present in the Boraflex.
Other conservatisms in the safety analysis ensure adequate safety
.
margins are being maintained when compared to the actual fuel that could be plaged in Region I (burnable poisons, less reactive fuel, etc.),,
The licensee intends on. generating more restrictive fuel loading limits
.whilepursuingalicenseagendment.
c.
Conclusion The inspectors concluded that no immediate sa'fety issues existed for the potentially degraded SFP Region I Boraflex condition.
The licensee's evaluation was prompt and proposed actions to develop more restrictive fuel loading limits were appropriate to ensure that adequate :riticality safety margins will be maintained.
E7 Quality Assurance in Engineering Activities E7.1 Emeroency Sumo Inventory and Emeraency Core Coolina System (ECCS)
Performance a.
insoection Scoce (37551)
The inspectors revicwed the )otential impact of a recent safety problem identified at the D.C. Cook luclear station since McGuire and Cook both have ice condenser containments. During an engineering audit at Cook, an issue was raised concerning the potential for inadequate emergency containment sump levels to support post loss of coolant accident (LOCA)
operation of the ECCS.
This 30tential condition at the Cook facility resulted in both Cook units slutting down in accordance with their Technical S)ecifications.
The inspectors reviewed the UFSAR and discussed t1e issue with McGuire personnel.
Enclosure 2
._____-_ _ _ -
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b.
Observations and Findinos The specific concern at D.C. Cook involved sump levels following a small break LOCA without substantial ict melting from the actuation of the ice condenser system. A condition may exist where insuff'cient drainage to the recirculation sump could result 4.n low water levels in the sump. A low sump level could jeopardize long term operation of the ECCS and containment spray pumps due to air entrainment from vortexing in the sump.
'
At McGuire, the licensee evaluated the issue and concluded that it was not a concern.
This conclusion was based on significant design differences between McGuire and Cook, such as:
Cook's emergency sump is inside the trane wall.
.
Cook has a containment spray header in the lower containment pipe
chase (toenhancepostaccidentiodineremoval).
!
There'is no appreciable communication between the pipe chase and
.
the emergency sump.
'
~
In addition. the licensee has evaluated the McGuire emergency sump inventory following a small'-break LOCA and concluded that sufficient water would be present to support long-term EECS and containment spray operation. This evaluation was performed before the Cook issue was identified and was documented in PIP 0-M97-2850.
Conclusion The inspectors concluded that the licensee's evaluation of the emergency sump inventory issue recently identified at another ice condenser facility was good, and that the issue w6s not a concern at the McGuire facility.
E8 Hiscellaneous Engineering Issues (92902)
E8.1 (Ocen) URI 50-369.370/96-04-02:
FSAR inconsistencies (FSAR items documented in Inspection Report 96-01 may be in non-compliance with 10 CFR 50.71(e).)
Additional examples were captured under this existing URI. as discussed in paragraph E3.1.
.
Enclosure 2 l
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IV. Plant Sucoort R1 Radiological Protection and Chemistry Controls l
R1.1 Transoortation of Radioactive Materials a.
Insoection Scone (86750.71750)
l The inspectors evaluated the licensee's transportation of radioactive i
!
materials )rogram for implementing the Department of Transportation I
(DOT) and 4RC transportation regulations for shipment of radioactive
materials as required by 10 Code of Federal Regulations (Li~R) 71.5 and 49 CFR Parts 170 through 189.
b.
Observations and Findinas The inspectors observed preparations for a shipment of radioactive materiai, The inspectors reviewed the shipping papers which were prepared by the licensee and a shipping contractor and determined that they adequately:
assured that the receiver had a license to receive the material being shipped:. assigned the form. quantity type, and pro)er
. shi> ping name of t7e matedal to be shipped: labeled and marked t1e pac cage: placarded the vehi'ple: assured that the radiation and contamination limits were met: and assured emergency response procedures were attached.
,
Licensee procedure PT/0/A/4550/37. Empty NCS R52 Cask Receiving and High Radioactive Material Loading and Shipping. Revision 0. dated August 1.
1997 was reviewed during cask loading as well as the cask loading pre-job briefing package.
The inspectors observed the licensee following the procedural requirements.
In addition, the inspectors reviewed licensee contamination and radiation surveys of the cask and performed independent surveys to verify the licensee's results.
The radiation and contamination survey results of the cask at the time of the inspection were below regulatory limits for shipment.
c.
Conclusions Based on the above reviews, the inspectors determined that the licensee had effectively implemented a program for shipping radioactive materials required by the NRC and DOT regulations.
Enclosure 2
.
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i El'
V. Hanaaement Meetinct
X1 Exit Heeting Summary
-XI.1 The inspectors aresented the inspection results to members of licensee i
management at tie conclusion of tie inspection on September 29, 1997 and
'
October 3, 1997. The licensee / acknowledged the findings presented.
..
The -inspectors asked the licensee whether any materials examincd during i
the inspection should be considered _ proprietary.- No proprietary information was identified.
X122 On August 25, 1997, a Duke Energy-NRC interface / counterpart meeting was conducted at the Catawba Site. Numerous topics of common interest were discussed.
PA8TIAL LIST OF PERSONS CONTACTED
licensee
'
- Barron, B,, Vice President. McGwiire Nuclear Station-Boyle, J., Civil / Electrical / Nucle'ar Systems Engineering i
Byrum, W., Manager, Radiation Protection
'
Cash, M., Manager, Regulatory Compliance i
Copp. S., Manager Nuclear Regulatory Affairs
.
Cross, R.. Regulatory Compliance Dolan,- B., Manager Safety Assurance
'Geddie,-E., Manager, McGuire Nuclear-Station Herran, P,, Manager'. Engineering Jamil, D., Manager, Maintenance Michael. R., Chemistry Manager Cash, M.
Manager. Regulatory Compliance Thomas, K., Su3erirtendent Work Control-
. Thrasher, J., ianager. Modification Engineering Travis, B,, Manager, Mechanical Systems Engineering Tuckman, M., Senior Vice President. Nuclear Duke Power Company NRC C. Ogle. Division of Reactor Projects. Chief. Branch 1-
- S. Shaeffer Senior Resident Inspactor-M.- Sykes,; Acting Senior Resident Inspector M. Franovich, Resident lnspector N. Economos. Regional Inspector-D.- Forbes, Regional Inspector
,
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Enclosure 2
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INSPECTION PROCEDURES USED IP 71707:
Conduct of Operations IP 62707:
Maintenance Observations IP 61726:
Surveillance Observations IP 40500:
Self-Assessment IP 37551:
Onsite Ei.gineering IP 71750:
Plant Support IP 86750:
Solid Radioactive Waste Management and Transportation Of Radioactive Materials IP 92902:
Follow up - Maintenance IP 50001:
Steam Generator Replacement IP 62700:
Maintenance Observation IP 92700 Onsite Follow up of Event Reports IP 93702 Pcompt Onsite Event Response ITE,MS OPENED. Cl0 SED, AND DISCUSSED
'
OPENED 50-320/97-15-01 V10
'Fahlure to Follow ET Analysis Guidelines (SeptionM8.1)
50-369,370/97-15-02 NCV Failure to Evaluate Material Suitability With Respect to Aluminum in the Reactor Buiiding (Section E2.1)
50-369,370/97-15-03 NCV Failure to Implement the Requirements of TS
!
3.4.4 (Sc: tion 02.1)
50-369.370/97-15-04 NCV Failure to Implement the Requirements of TS 3.3.3.1 (Section 02.1)
50-369.370/97-15-05 IFI Reduction of FSAR Drawing Detail (Section E3.1)
CLOSED 50-370/97-09-02 URI Steam Generator Inspection Process (Section M8.1)
50-369/96-05 LER Technical Jaecification Required Shutdown of Both Units Jue to a Failed Surveillance Test of Vital Battery EVCC Caused by an Unknown (Section 08.1)
Enclosure 2
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l
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L DISCUSSED-l 50-369.370/96-04-02-URi-FSAR Discrepancies (Section E3.1)
!
LIST.0F ACRONYMS USED l
TAuxiliary feedwater AFW-
--
ALARA -
As low As Rersonably-Achievable -
ASME American Society of Mechanical Engineers-
-
BWI Babcock Wilcox-International
-
CF-Main Feedwater
-
>
-
-CFR Code of Federal Regulations
-
'
--. CR Control Room
-
DOT Department of Transportation
-
ECCS Emergency Core Cooling System
--
-
EDG-Emergency Diesel Generator
-
-
ET -
-
ESF. -
Engineered S$fety Feature FWDS --
Field held Data Sheet FWST Feedwater Storage Tank
-
GL
,-
Generic Letter
,,,
HEPA High Efficiency. Particulate Air
_
-
High Pressure
-
.IFI-Inspector Follow up Item
-
,
IR
.Insnection Report
-
,
-LER-Licensee Event Report
-
LOCA -
Loss of Coolant Accident MDAFW --
Motor Driven Auxiliary Feedwater
- MFW'
Main Feedwater
--
MOV. - -
Motor-0perated Valve MPFF
- Maintenance Preventable Functional Failure
-
MRPC Motorized Pancake Coil
=
.
MSSV -
Main Steam Safety Valve NDF -.
'No Defect Found
-
-NCV
.Non-Cited Violation
.-
-NOI-Non-Quantifiable Indication
-
NRC Nuclear Regulatory Commission
-
NRR-NRC Office of Nuclear Reactor Regulation
-
NSRB- -
Nuclear Safety Review Board
.PCE_.-
Personnel Contamination Event POR
-
Public Document Room PIP.=
Problem Investigation Process
-
PM:
' Preventive Maintenance.
-
-PORC -
Plant Operations Review Committee PORV Power Operated Relief Valve
--
PSIG Pounds per Square Inch Gauge
-
'PT _
Periodic Testing
-
-
RCA Radiological Controlled Area
-
RIC Retest Incomplete
-
c Enclosure 2
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_ _ _
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,
,
.
RSG Replacement Steam Generator
-
RWP Radiation Work Permit
-
SFP Spent Fuel Pool
-
-
SGR Steam Generator Replacement
-
SI-Safety Injection
,
'
-
SSPS Solid State Protection System
-
TDAFW -
Turbine-Driven Auxiliary Feedwater TEDE Total Effective Dose Equivalent
-
i TM Tem3orary Modification
-
i TS Tec1nical Specifications
!
-
UFSAR -
Updated Final Safety Analysis l
URI Unresolved Item
-
'
US0 Unreviewed Safety Question
-
V.' ",
Volts Alternating Current
-
VDC Volts Direct Current
-
VIO Violation
-
-
Work Order
,
e e
.
e f
e j
Enclosure 2
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