IR 05000424/1997010
| ML20202E222 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 11/26/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20202E120 | List: |
| References | |
| 50-424-97-10, 50-425-97-10, NUDOCS 9712050296 | |
| Download: ML20202E222 (37) | |
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U. S. NUCLEAR REGULATORY COMMISSION (NRC)
REGION 11 Docket Nos. 50-424 and 50-425 License Nos. NPF-68 and NPF-81 Report No: 50-424/97-10. 50-425/97-10 Licer.see: Southern Nuclear Operating Company. In Facility: Vogtle Electric Generating Plant (VEGP) Units 1 and 2 Location: 7821 River Road Waynesboro. GA 30830 Dates: September 21. through November 1. 1997 Inspectors: M. Widmann. Acting Senior Resident Inspector K. O'Donohue. Resident Inspector R. Caldwell. Resident Inspector. Farley (Sections E8.1. E and E8.3)
C. Rapp. Project Engineer (Sections 08.3 and E3.1)
W. Kleinsorge. Reactor Inspector, Region II (Sections M M1.4. and M1.5)
Approved by: P. Skinner. Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure 2 9712050296 97f126 gDR ADOCK 05000424 PDR
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EXECUTIVE SUMMARY Vogtle Electric Generating Plant Units 1 and 2 NRC Inspection Report 50-424/97-10. 50-425/97-10 This integrated inspection included aspects of licensee operation engineering, maintenance, and plant support. The report covers a six-week period of resident inspection. It also includes the results of an announced inspection by a regional maintenance inspecto Doerati m
. Plant management's conservative decision making was demonstrated when the licensee elected to avoid a fueled midloop during 1R7 (Section 01.1).
- Performance of startup activities from the Unit 1 refueling outage were in accoraance with procedures (Section 01.3).
. Opening the reactor trip breakers in response to the Digital Rod Position Indication (DRPI) was appropriate during startup testing on Unit 1 (Section 01.4).
. An example of poor work practices was identified that resulted in an inadvertent dilution event during a demineralizer flush activity (Section 01 5).
. The reactor operators' response to the ind1'cated plant conditions and the resultant transient was excellent (Section 01.5).
. Another example of poor work practices was identified when a lack of communications resulted in failure to properly block a containment radiation monitor. This activity resulted in an inadvertent emergency features actuation (Section 01.6).
. The Emergency Safety Features (ESF) systems reviewed were available to perform their intended design function, were properly aligned. and Technical Requirements Manual (TRM) commitments and Technical Specifications (TS) reouirements were met (Section 02.1).
. A violation was identified for improper control and alignment of diesel generator unit heater 480-volt breakers (Section 02.2).
. A weakness was identified for multiple examples of a failure to properly review procedure revisions in accordance with an established procedur The procedure revision errors directly impacted the operation of the plant during performance of these procedures (Section 03.2).
f . A weakness was identified for the operations crew in not recognizing l that Unit 1 entered and exited a TS Limiting Condition for Operation for an emergency core cooling system (Section 03.2).
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Enclosure 2
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- The licensee was in compliance with TS requirements for plant staff hours (Section 08.1).
- The licensee's implementation of a new program to clean the containment prior to the performance of a closecut exit inspection has adequately addressed previously identified loose debris issues and should preclude repetition. The increased emphasis that the licensee placed on material control within containment during 1R7 achieved successful results (Section 08.2).
Maintenance
- A non-cited violation related to failure tc follow a magnetic particle examination (MT) procedure was identified (Section M1.3).
- Inservice inspection activities observed / reviewed were conducted in accordance with procedures licensee commitments, and regulatory requirements (Section M1.3).
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- The licensee's programmatic coverage of arc strikes was considered a weakness (Section M1.3). s
- Unit 1 steam generator #4 tubesheet rework activities were supported by appropriate evaluations and controlled by well written procedures and highly trained and motivated individuals (S ction M1.4).
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Unit 1 split pin replacement activities were supported by appropriate evaluations and controlled by well written procedures and highly trained and motivated individuals (Section M1.5).
- Troubleshooting efforts implemented during outage work involved the proper personnel, procedures and work orders were developed in a timely manner, and activities erformed were in accordance with procedure guidance (Section M1.6)
- Diesel Generator Train A and B and engineered safety features actuation system (ESFAS) testing were performed in accordance with written procedures and were well controlled (Section M3.1).
- Emergency Core Cooling System Flow Test. performed in accordance with written procedures which incorporated a new testing method, was well controlled (Section M3.2).
- A non-cited violation was identified for maintenance calibration procedures implemented during the outage that left instrument setpoints outside the trip setpoints stated in technical specifications (Section M8.1).
Enclosure 2 I
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Engineerim
. The licensee's design change package (DCP) 97-VlNOL22 was complete and sufficiently detailed, and implementation of the valve modification during the Unit 1 seventh refueling outage (1R7) was satisfactory (Section E2.1).
. A violation was identified for the licensee not fully implementing developed corrective actions for use of the APEX users manual prior to the startup of Unit 1 (Section E3.1).
. The licensee review for LER 50-424/96-005 was not adequate in that it did not identify the full scope of the Eaton Cable splicing issue (Section E8.1).
. A weakness was identified in the area of deficiency card review process for tne lack of clear guidance for the determination of Maintenance Preventable Functional Failures (Section E8.3).
Plant Sunoort
. The removal and storage activities for the lower guide tube were well controlled, coordinated, and in accordance with the vendor procedur Worker precautions were appropriat The licensee *s awareness of radiological and personnel safety associated with this activity was identified as a strength. (Section R1.1).
. A non-cited violation was identified for a contract worker leaving the plant after performance of a self-decontamination activity (Section R3.1).
Enclosure 2
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! Renort Details Summary of Plant Status Unit 1 began the inspection period defueled. Mode 6 was entered October . fuel reload and core verification was completed October 13. On October 20. mode 2 was entered, the unit was taken critical, and low power physics testing performed. Mode 1 entry occurred October 22 at 0024. the unit output breaters were closed at 2258 the same day. Power ascension followed. The inspection period ended with Unit I at 100% powe Unit 2 operated at full power throughout the entire inspection perio . OperatioM 01 Conduct of Operations 01.1 General Coments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general. the reviews indicated that the conduct of operations was satisfactor On approximately October 10. 1997, the inspectors were informed that the licensee had elected not to enter a reduced inventory condition with fuel in the vessel. Instead. the licensee elected to incur a > proximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> of critical path time in the outage thereby o)viating the need for a fueled midloop. The inspectors concluded that this was a conservative decision on the part of plant managemen .2 Core Reload (60710)
The inspectors observed the majority of the Unit 1 fuel relrading activitie The inspectors reviewed Procedures 93300 . b nduct of Refueling Operations." Revision (Rev.) 17. and 93100-C. " Refueling Tools and Equipment Preservice inspection /Chectout." Rev. 8. In addit un, the inspectors observed the site reactor engineering initial core verification activit.ies and portions of the second verification (i .c. .
reactor engineering personnel compared the video tape recorded during initial verification activities to the reshuffle plan).
Based on this review the inspectors concluded that the licensee reloaded the core in accordance with their reshuffle plan. Refuel activities were performed in a controlled manner and in accorJance with specified procedures. No discrepancies were identified by the inspectors during the reload proces .3 Unit 1 Startun Observations (71707)
The inspectors observed selected )ortions of the Unit 1 startup coming out of 1R7. Activities observed )y the inspectors included the entry t; Enclosure 2
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mooe 6. core reload, entry into modes 5. 4. and 3. rod drop tests, plant heatup, reactor thermocouples cross calibrations. transition into mode 2. low power physics testing and power escalation in preparation for turbine loading. The performance of these evolutions were in accordance with procedure .4 Manual Reactor Trio .lpspect ion Stone (71707)
The inspectors reviewed the circumstances surrounding the Unit 1 manual reactor trip of October 19. During the performance of Procedure 88006-C. " Rod Dro] lime Measurement with Rod Drop Test Cart ' Rev. the reactor trip areakers were manually opened due to ina)propriate rod alignment indication. The inspectors reviewed the shif t ]riefing notes, log entries, applicable procedures, and the Technical Requirements Manual (TRM). The inspectors interviewed the operations personnel involved and discussed the trip with licensee managemen Observations and Findinos While in mode 3. the reactor trip breakers were closed to allow for hot rod drop testing per Procedure 88006-C. Shutdown bank 'A' was being withdrawn for the test. The Digital Rod Position Indication (DRPI)
system was expected to alarm during the withdrawal due to a ]reviously identified DRPI coil deficiency. Rod M-2. part of shutdown ]ank "A".
had a malfunctioning data "B" coil such that when that rod was approximately 48 to 52 steps withdrawn the DRPl indication became erratic. DRPI alarms and indication were expected to return to normal status once the rod was pulled through that step range. This expectation was based on previous experience with the malfunctioning col During the hot rod testing DRPI alarms came in as expected, however, they did not clear once the shutdown bank was withdrawn past step 5 Because indication discrepancies for Rod M-2 were anticipated the reactor operator continued to withdraw the shutdown bank. Once past step 52, the DRPl od bottom light for Rod M 2 cleared, however, the indicated position for Rod M-2 was iden!.1fied as being beyond the required alignment of 12 steps. After stopping the withdrawal of shutdown bank "A". the reactor operator identified the difference between Rod M-2 and the rest of the bank to be greater than 12 steps and opened the reactor trip breakers as required by TRM 13.1.9. ' Test Exceptions for Position Indication System Shutdown." Action Statement
"A". This event was re)orted per 10 CFR 50.72 as a reactor protection system actuation (four-lour notification).
Enclosure 2
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l 3 Conclusions The inspectors concluded that opening the reactor trip breakers in response to the DRPI was appropriat .5 Ina 'vertent Dilution Inspection Scone (71707),
During the reactor startup, the inspectors observed that reactivity additions were generally well coordinated and involved appropriate oversight on the part of the licensed operators with the exception of an inadvertent dilution wnich took place October 21. As a result of the event. the inspectors reviewed Procedure 13009-1, * Chemical Volume and Control System Reactor Makeup Control System," Revision 19: 13701 1,
- Boric Acid System," Revision 18, control room logs, computer graphs and calculation sheet Observations and Findinas On October 21, 1997, Unit 1 in mode 2 at approximately 2% power. During flushing of the Chemical Volume and Control System (CVCS) mixed bed demineralizer #3, an inadvertent dilution occurred that resulted in a power increase of 2.6%. However, when the reactor operator observed the unex)ected power increase. control rods were immediately inserted and the teactor Coolant System (RCS) borated to return reactor power to the initial level of 21. Computer data indicated that reactor power went f rom approximately 2% to 4.6%.
The inspectors identified that on October 20. 1997, the Boric Acid Storage Tank (BAST) received boric acid makeup throughout the nigh Night shift personnel placed the BAST in recirculation at 5:00 a.m. on October 21. At 7:00 a.m.. it was noted during shift turnover that the BAST required additional makeup. Operations :>ersonnel continued to mdkeup to the BAST during the morning of Octo3er 21 while the BAST was in recirculation. Chemistry was not contacted to take a sample for boron concentration from the BAST during or after the makeup activitie At 1:00 p.m. October 21, the CVCS demineralizer #3 was flushed prior to being placed in service to ensure the demineralizer was at the current RCS boron concentration. As part of the flushing process the CVCS letdown flow was diverted to the recycle holdup tank. As a result of the letdown flow diversion. the Volume Control Tank (VCT) level decreased. Volume Control Tank level wcs manually restored using a blended flow from the BAST and Reactor Make-up Water Storage Tank (RMWST). The operators calculated the ratio of boric acid to demineralized water b5 sed on the BAST boron concentration that was posted on the control board. It was later determined that the boron concentratu n posted in the control room was from a chemistry sample that was ani.lyzed prior to the initial makeup to the BAS After Enclosure 2
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response to the inadvertent dilution. the licensee determined that the actual BAST boron concentration was lower than the boron concentration 1 posted in the control room, i i
The BAST boron concentration sample data was not discussed during shift turnover, therefore, makeup calculations were based on the last known ,
a sam)le. Chemistry sampling measured the actual BAST boron concentration
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on October 21 to be 6986 parts per million (ppm). The concentration i
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used by the operators to calculate the quantity of acid to be added to the RCS was based on a sample taken October 1 lhe difference between the actual concentration of October 21 and the sample of October 17 was 489 ppm. This error resulted in a makeup ratio that consequently diluted the RCS boron concentration, adding positive reactivity, and directly cau ing reactor power to increase. The licensee formed an event review team to examine the inadvertent dilution and identify any
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appropriate corrective action !
Ouring review of this event, the inspectors determined that making up to the BAST during the required post-addition 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> tank recirculation was not procedurally prohibited. However, making up during BAST recirculation negates the intent of the post addition 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> tank recirculation. Batching during recirculation prevents the BAST volume from being properly " turned over" which prevents sampling from depicting actual plant condition .
c, Conclusiorls
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The inspectors concluded that the inadvertent dilution event and resultant power increase on October 21, 1997, was the result of poor work practices by operations personnel in conjunction with out dated chemistry sampling data. This issue is identified as an example of poor work practices. The ins)ectors also concluded that the reactor operators' response to tle indicated plant conditions and the resultant i transient was excellen .6 Control Rod Drive Shaft Activity Results in inadvertent Emeroency Safety feature (ESF) Actuation Insnection Scone (71707)
On October 14. 1997, during removal of a control rod drive shaft from inside containment, a Containment Ventilation Isolation (CVI) signal was received in the Unit 1 main control room. The inspectors reviewed the circumstances surrounding this ESF actuation. The inspectors reviewed
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the event notification worksheet and the event report investigatio The inspectors also discussed the incident with cognizant operations
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Enclosure 2
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5 Observations and Findinas During an activity to remove a suspected damaged control rod drive shaft from containment, the control rod drive shaft was moved in close '
proximity to radiation monitor 1RE-002 and a CVI occurred. The plant '
was in mode 6 at the time of the event. The radiation monitor actuation setpoint was 15 mrem / hour. Maximum radiation readings recorded were approximately 25 mrem / hour. All ESF components actuated as require Based on the licensee's investigation, this incident occurred as a result of poor comunication between workers inside containment and operations personnel in the control room. During a pre-job briefing the licensee designated a worker inside containment to contact the control room prior to the control rod drive shaft being lifted. The communication was to prompt operations personnel to place radiation monitors located inside containment in the " block" position to avoid a CVI signal. That communication did not occur. A Licensee Event Report (LER) 1s being developed by the licensee, Conclusions The licensee determined that the incidcnt was a result of cognitive personnel error. The poor communication associated with this event is identified as another example of poor work practice Operational Status of Facilities and Equipment l
02.1 Safetv Related Walkdowns (71707)(61726) Insoection Stone
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The inspectors walked down the following ESF systems as part of the routine inspection effort to verify availability and overall condition of the safety-related systems:
Unit 1 Essential Chilled Water System. Train A Unit 2 Essential Chilled Water System. Train B Unit 1 Residual Heat Removal System. Train A and B l The inspectors also performed a review of TRM and Technical l
Specifications (TS) requirements for the above listed systems.
i Observations and Findinas I The ins)ectors verified proper system configurations both electrically and mecianically for the above ESF systems through accessible portions in the plant, walkdowns of main control room boards. and reviews of system drawings and procedures. The inspectors also observed overall material condition of system components during the walkdowtis. The inspectors identified some minor issues which were provided to the licensee for resolutio Enclosure 2
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' Conclusions The inspectors concluded that the systems reviewed were available to perform their intended designed function: systems were properly aligned: .
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and TRM commitments and TS requirements were met. No significant items or discrepancies were noted during these observation '
02.2 Unit 1 Diesel Generator 480-Volt Breakers Mis-Positioned ;
. Inspection Scone (71707)
As part of the core module inspection the inspectors conducted system alignment walkdowns. The inspectors reviewed procedure lineups and systems drawings. The ins motor control center (MCC)pectors compared actual breaker Jositions specified positions in onINB Procedures 11145-1. " Diesel Generator Alignment." lev. 11: Procedure 11429 1. "480V AC 1E Electrical Distribution System Alignment," Rev. 13:
and 11430 1. "480V AC Non IE Electrical Distribution System Alignment,"
Rev. 12. The inspectors also discussed the issue with cognizant operations managemen . Dbservations and Findinas
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On October 3, 1997, the inspectors conducted a walkdown of the 480 Volt breakers on MCCs 1NBG, INBl. and 1ABF which were located inside the Unit 1 Diesel Generator (DG) train A building. All load equipped breakers were properly )ositioned with the exception of' breakers on 1NB Specifically, >rocedure 11430 1 required that breakers in MCC INBG be 4 closed unless tagged. The inspectors observed that 10 unit heater breakers were open and not tagge The insnectors determined from a roview of the clearance database that
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the unit heater breakers were not under clearance when the MCC 1E and L Non 1E lineups were last completed.
l The licensee informed the inspectors that the licensee's subsequent review of the breaker alignments determined that during the seventh refueling outage various maintenance work was performed on DG 1 During one of those activities maintenance personnel requested that the unit breakers be turned "off" due the heaters unnecessarily cyclin The request was communicated to operations personnel but was not logged .
or controlled in accordance with the plant approved procedure 00304- " Equipment Clearance and Tagging," Rev. 3 As a result, no mechanism was in place to ensure that the unit heater breakers, at the conclusion of the maintenance activity, were re-aligned in accordance with electrical system lineup procedure 11430-1, The failure to properly
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position the DG 1A unit heater breakers on MCC INBG in accordance with the requirements of Procedure 11430-1 was identified as Violation (VIO)
50-424/97-10-01, Mis-Positioned Unit Heater Breakers On 480-Volt MCC INBG, 1 Enclosure 2
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The licensee determined that the breakers were mis-positioned for approximately three days until identified by the inspectors. The inspectors noted that plant operators had performed their area rounds for those specific three days and did not recognize or question the ,
breaker positions, Conclusions The ins)ectors concluded that the safety consequence of the ten unit heater areakers being open on 1NBG was minimal. The inspector identified a violatit associated with a lack of control of heater breakers on MCC INBG.
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03 Operations Procedures and Documentation 03.1 Walkdown of Clearances (71707)
During the inspection period, the inspectors walked down the follov!ing clearances:
19602885 Diesel generator IA end-of-cycle maintenance
- 19715002 Reserve auxiliary transformer INXRB (RAT-18)
- 19715101 1R7 Reactor Coolant Pump (RCP) #1 (electrical only)
19715104 1R7 RCP #4 (electrical only)
19715106 Reactor coolant system drain down 19715111 RCP # 1 seal injection 19715121 Auxiliary Component Cooling Water isolation and drain to all RCPs 19715181 Seal injection loops 1, 2. and 4 valve work 19715810 Main feedwater pump turbine B vapor extractor 19715899 Containment building cavity cool unit fan #2 19716029 1R7 air pressure test for 6A and 5A feedwater heaters 19716030 Isolation of shell side of 6B and 5B feedwater heaters 19716104 Chemical volume and control, reactor coolant system isolation valve Ot servations and Findinos
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The inspectors did not identify any significant problems or concerns during these walkdowns. Minor issues were provided to the licensee for
. resolution. During the installation of clearance 19715002 a reactor operator identified that the clearance included the removal of an incorrect control power breaker from service. The clearance error was corrected. The inspectors concluded that this was an example of good attention to detail on the part of the operato Enclosure 2
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03.2 Procedure Review Process (71707) Insoection Scone
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The inspectors reviewed the circumstances surrounding several recent [
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. procedural problem The procedures described below were recently revised. Each revision resulted in unexpected plant condition that had !
an unexpected respons Summarized below are event details related to !
the procedural revision error : Observations and Findinns Procedure 148101. " Turbine Driven Auxiliary Feedwater (TDAFW) Pump and l Check Valve Inservice Test (IST) Response Time Test." Rev. 23. was performed on August 4.1997. The performance of Rev. 23 resulted in the !
introduction of auxiliary feedwater into all four steam generator i
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This issue wan previously documented in Inspection Report 50 42 /97 09. It was determined during the previous review of the event that when step 5.2.5 of procedure 14810 1 was performed, an open signal i was received at all four of the TDAFW motor operated discharge flow ,
control valves. Because the TDAFW pump was operating at that tim Auxiliary Feedwater (AFW) was fed to all four steam generators. The ;
' licensee revised Procedure 14810-1 on May 30. 1997, to delete a step i that manually closed the TDAFW discharge isolation valve. 1-1302-U4 01 :
Procedure 14810-1 was revised to comply with an NRC commitment to !
maintain that valve open at full power operatio The procedure !
revision review performed by operations management did not recognize
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i that the deletion of the step to close the manual valve would result in '
AFW injection into the steam generator l Procedure 14667-1. " Train B Diesel Generator and Emergency Safety Features Actuation System (ESFAS) Test." Rev. 5. Section 5.2. "Lcss of ;
Off Site Power Concurrent with Safety Injection (SI),' was performed on l October 8. 1997. When the Si signal was initiated, with the power !
supply to the 4160 lE electrical bus isolated. the diesel generator did not start. Operations personnel restored power to the 416D bus per abnormal o)erations procedure 18031 C. " Loss of Class lE Elect System."
Rev. 15. Juring the event review, it was determined that the Rev. 5 !
procedure changes added steps intended to allow testing of the diesel generator start signal from Si actuation. However, the revised
- procedure steps resulted in the isolation of the control air from the DG auto start circuit, thereby preventing the diesel generator from starting. During the procedure review and approval process it was not recognized that control air would be isolated during performance of this i ESFAS test. The safety significance of this event was minimal since
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Unit I was defueled at the tim '
On October 18.-while performing Procedure 12002 C. " Unit Heatup To Normal Operatfng Temperature and Pressure.~ Rev. 34. the SI system was made inoperable due to opening SI discharge valves to the hot leg j
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1HV-8802A and 1HV 8802 The plant was in Mode 3 when it vias discovered that the valves were mis positioned. Operations personnel performed checklist 3 of Procedure 12002-C which was intended to aligned the Si system to operable status. However, the valve and 1HV 8802B were erroneously listed as "0 PEN rather than* positions
- CLOSED".for 1HV 8802 As a result, the misalignments made the safety injection system inoperable. Approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> later, operations personnel identified the misalignment and immediately closed the valves. After the valves were discovered to be mis-positioned. o)erations personnel reviewed the TS and determined that Unit I was wit 11n the four hour grace period allowed in Note 2 of TS 3.5.2. Emergency Core Cooling System (ECCS) Operating. However after reviewing the plant conditions, the inspectors determined that TS 3.5.2. Limiting Condition for Operation (LCO) Action Statement "A" had been entered since the second part of TS 3.5.2 Note 2 stated that two trains of ECCS must be operable prior to exceeding 375 F in all four RCS cold legs. Based on a review of RCS cold leg temperatures, after entry into Mode 3. the licensee operated above the 375 F limit with for approximately 1-8 hour However, the safety significance of the issue was minimal due to the licensee meeting the LCO Action Statement 'A' completion time well within the required 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> The inspectors determined that Procedure 00051 C. * Procedures Review and Approvai." Rev. 24. required review of the revised procedures by qualified personnel which may include review by the Plant Review Boar The inspectors verified that the procedure revision packages indicated that the appropriate reviews were performed where necessary. However, the reviews performed on these revised procedures did not effectively identify the errors prior to use of the procedure Conclusions The inspectors concluded that each event discussed above resulted from errors introduced during the revision process. The errors and discrepancies identified were not recognized during the review and approval process. The inspectors identified a weakness in the review and approval process for revisions to procedures. The inspectors also concluded that the failure of t h operations crew to recognize the entry into the applicable LCO Action Statement for an inoperable ECCS System was a weaknes Hiscellaneous Operations Issues (92901)
08.1 &ngonel Outaae Work Time a. inspection Scone (.Z1707)
The inspectors reviewed a random sample of time sheets and overtime records of plant staff and contractors during 1R7. The inspection was conducted for plant staff that performed safety-related functions to Enclosure 2
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verify compliance with TS 5.2.2.e. Unit Staff, and to review the overtime authorization process. The inspectors reviewed licensee i documentation including personnel payroll time sheets, personnel :
l on site logs, andtime as determined Procedure 00005 C. by" Overtime Aut1orization." Rev. 8. security com)uLe ' Observations and Findinas ne inspectors reviewed time sheets for personnel in operation ,
electrical and mechanical maintenance, health physics lip)/ chemistry, and instrumentation and control (I&C) departments. In addition, the ,
inspectors reviewed various contractor employee time sheet ,
Tra inspector noted, during the review, that deviations from TS 5.2. guidelines were approved in accordance with procedure 00005 The ins)ector verified that Procedure 00005-C-included controls to limit worting hours as required by TS 5.2.2.e. However, the inspectors noted that excess overtime authorization forms were not readily available for '
review for all personnel. The review indicated that approximately 10%
of operations personnel and approximately 50% of maintenance personnel r did not have " signed" overtime authorization sheets. Based on discussions with licensee management overtime was " verbally" approved, but the time was not documented properly. Verbal approval was permitted in accordance with 00005-C. The missing time sheets identified were in the process of being generated during the inspectors review.
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The inspectors also noted, as a result of this review, that overtime authorized for 1R7 increased over that authorized for previous outage The licensee indicated that the increased time was a result of a longer ,
outage (approximately 45 days) and less available resources. However, i the inspectors determined that the overtime for safety related work l authorized by plant management met the requirements of TS 5.2.2.e. - The overtime was used during an extended period of shutdown for refuelin Conclusions The inspectors concluded that the licensee was in compliance with TS requirements for plant staff hour in addition. the inspectors noted that deviations from TS 5.2.2.e requirements were approved in accordance with procedure 00005 C. Based on the inspectors' review, no abuse of '
overtime was identifie ,
P Enclosure 2
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08.2 (Closed) VIO 50-424/97-04-01: Containment Debris identified During Unit :
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1 Planned Outage (1P1)
(Closed) VIO 50 425/96 11-02: Inadequately Performed Surveillance to i Closeout Unit 2 Containment , inspection Scope (71707)
As a result of previous issues identified with containment closeout, the inspectors conducted a containment exit inspection October 18. 1997. As i
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part of this inspection, the inspectors reviewed Procedures 14900 " Containment Exit inspection." Rev. 3: and 14903-1. " Containment !
Emergency Sump Ins
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debris identified,pection." Rev. 7. theengineering and the subsequent Deficiency evaluation Card (DC)todocumenting assess the impact on sump performanc ,
' Observations and Findinas On October 18, 1997, the inspectors conducted an inspection of Unit 1 containment to assess material condition prior to startu). At the time -
of the inspectors' entry into containment, the licensee lad completed
. their preparation of containment and were in Mode In general, the material condition within containment was much improved from 7 425/9)reviousinspections(referenceInspectionReports50-424,However,
- 04 and 50-424, 425/96-11), the ins two noteworthy items inside containment in addition to pieces of debris .
'
within readily accessible areas of containment. A respirator in a sealed bag, and a fire extinguisher were identified on the 220 foot elevation of containment. The miscellaneous debris identified was randomly distributed throughout various levels of containment. The inspectors also identified several minor material deficiencies for licensee resolution, t An engineering evaluation estimated the total amount of debris and [
miscellaneous materiais removed by the inspectors at approximately two square feet. Based on results of the licensee's engineering analysis of ,
the material, containment sump performance was not impacted or rendered degrade In addition, the items identified were not of sufficient ,
quantity to significantly affect the post accident water chemistry, fire protection analysis, flooding analysis, peak clad temperature analysis, containment 3ressure/ temperature analysis. or the hydrogen generation analysis. T11s conclusion appears reasonable based on tne nature and 1 amount of material,
' [.qnclusions 4 The inspectors concluded that while the items identified did not represent a substantia,1 challenge to containment sump performance, the "
loose debris should have been resolved as a result of the licensee's Enclosure 2
.
e
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closeout of containment. Overall. the inspectors concluded that the licensee's implenentation of a new program to clean containment prior to the performance of a closeout exit inspection has adequately addressed previously identified loose debris issues. The increased emphasis that the licensee placed on material control within containment during 1R7 achieved successful result .3 (Closed) Inspection Follow Un item (IFI) 50-424. 425/97-08-01:
Resolution of Self-Assessment findings This IFl concerned disposition of comments and recommendations resulting from an Independent Safety Engineering Group (ISEG) review and a self-assessment of the Plant Modification and Maintenance Su; port (PMMS)
organization. The ISEG comments were provided only as a feedback and did not require a response. However, the ISEG organization clarified its guidance to state that a specific response request and due date will be included whenever a response is expected. The PMMS self-assessment comments were routed to the responsible organizdtion for respons Based on this review the inspectors concluded that the licensee has adequately addressed this issue. This IFl is close .4 (Closed) LFR 50 424/97-006. Hydrogen Monitoring System Train Rendered 1,1 operable This issue was determined to be of minor safety significanc This LER is close I Maintenance M1 Conduct of Maintenance M1.1 Maintenance Work Order Observations inspection Scooe (62707)
The inspectors observed portions of maintenance activities involving the following work orders:
A9700877 Control room door seals replaced 19601736 Diesel generator air start receiver relief valve 19602190 Replace reactor coolant pump number 3 internals 19612931 Core reload 19602941 Reactor head lift and reassembly
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19602952 Tension reactor heao studs 19602954 Assemble conoseals 19700123 Remove / Replace pressurizer safety valve snubbers 19700541 Replace snubber ll201030H60 on reactor coolant system 19700857 Support pin lower guide tube replacement l
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Enclosure 2 i
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f 19701932 Cavity cooler coil replacement (DCP VAN 0021) i 19702923 Investi9 ate and repair indication on 1HS-7144 ;
19702935 Dit.sel generator train B jacket water leaks :
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19702996 Hydrostatic test and reactor coolant pump seal installation 19703240 Control rod M 2 trouble shooting i 29702539 Containm%t condensate cooler leak detection Observations and findinas .
The observed maintenance activities were generally completed thoroughly and professionall l M1.2 Surveillance Observatiorl Insnection Scope (61726)
The inspectors observed the performance or reviewed the following surveillances and plant procedures:
14005-2 Shutdown Margin Calculations. Revision (Rev.) 11 14240 1 Manual Steamline Isolation TADOT (Trip Actuation Device
'
Operability Test). Rev. 2 14406-2 Boron injection Flow Path Verification - Shutdown Rev. 7 14546-1 Turbine Driven Auxiliary feedwater Pump Operability Tes Rev. 7 14710-1 Remote Shutdown Panel Transfer Switch and Control Circuit 18-month Surveillance Test (IAA02). Rev. 20 14727-C Load Tests for Refueling Machine and Auxiliary Hoist. Rev. 3 14748-1 Auxiliary Feedwater Pump and Check Valve Cold Shutdown Inservice Test and Turbine Driven Auxiliary Feedwater Pump Auto Start Test, Rev. 16 14750 1 DRPI (Digital Rod Position Indication) 18-month Operability Test. Rev. 5 14786 C Turbine Driven Auxiliary feedwater Pump Overspeed Test. Re ;
14808-1 Centrifugal Charging Pump Train B and Check Valve IST (Inservice Test) and Response Time Test. Rev. 21 14809 2 ESF (Emergency Safety Feature) Chilled Water Pump Inservice Test. Rev. 9 14825-1 Quarterly inservice Valve Test. Rev. 40 14850 1 Cold Shutdown Valve Inservice Test. Rev. 28 24769-1 Accumulator Tank #2 Level IL-953 Channel Calibration. Re Refueling Water Storage Tank Level IL-991 Analog Channel Operational Test. Rev.13 27147-C Reactor Coolant Pump Seal Cartridge Static Test. Re C Reactor Coolant System RTD (Resistant Temperature Detector)
Cross-Calibration. Rev. 6 56003-1 DP (Differential Pressure) Test for 1-HV-1831. Rev. 1 88006 C Rod Drop Time Measurement (Cold) Test. Rev. 7 Enclosure 2
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T-ENG-97-12 Control Rod Drop Testing. Rev. I r T EN3-97-27 Ten (10) Year Class 1 Pressure Test. Rev. 0 T ENG-97-28 Centrifugal Charging Pump 1A Performance Test in Mode Rev. 0 .
b. Observations and findinos The observed surveillance activities were generally completed thoroughly ,
and professionall Performance of surveillance Procedure 14809 2. 'ESF Chilled Water Pump Inservice Test." Rev. 9, was observed by the inspectors. During the ,
surveillance. the initial indicated ESF Chiller #2 flow was below the flow range required by the procedure. Procedure step 5.2,6,4 directed the rate.completion Guidance of of section 5.3 inindicated step 5.2. order to obtain the apbropriate that section .3 was toflow be completed in its entirety. Section 5.3 did not allow for the adjustment of the flow rate and then a return to section 5.2. The last step of i section 5.3 directed the reactor operator to return the chill water thermostat temperature to the original setting which caused the flow rate to be returned to its original value. This ' circle" between sections 5,2 and 5.3 would not allow proper flow rate to be establishe After it was recognized that the procedure could not be performed as written the reactor operator backed out of the procedure. After a discussion with the Unit Shift Supervisor, a temporary procedure change was completed and the surveillance was performed without inc.iden M1.3 Inservice Insnection a. Insnection Scone (73753)
To evaluate the licensee's inservice 'nspection (ISI) program ano the program's implementation the inspectors reviewed selected records, procedures and observed work in 3rogress. Observations were compared with applicable procedures, the hdated Final Safety Analysis Re ort .
(UFSAR), and American Society of iechanical Engineers (ASME) Boi.er and Pressure Vessel (B&PV) Code Sections V and XI,1989 Edition, No Addenda (89NA).
Specific areas examined included the following observation: magnetic particle (MT) examinations of item Nos. 11201 V6-001-WO2 and 11301-001-13: liquid penetrant (PT) examination of item No. 11204-001-9: manual ultrasonic (UT) examination of Item Nos. 11301-001-1. 11301 001- , 11301-001-9. and 11301-001-10: data acquisition activities associated with eddy current (ET) examinations of steam generator (S/G)
tubing: and direct visual (VT) examination of su] port Nos, 11205-005-H013, 11205-007-H032, 11205-007-H033, 11205-On7 1041 and 11208 411-H01 Review of selected completed examination reports: and review of the Repair and Replacement Progra Enclosure 2
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Procedures reviewed included: UT V 404. * Manual and/or Mechanized Ultrasonic Examination of full Penetration Welds." Revision 9: HT-V-50 .
'
- Magnetic Particle Examination.* Revision 4: PT-V 605. Liquid Penetrant Examination Procedure." Revision 3: and VT-V 73 Visual Examination !
(VT 3)." Rev. l The inspectors performed an independent evaluation of indications to i confirm the licensee's 151 examiners' evaluations, j The inspectors reviewed records for the nondestructive examination (NDE) I personnel and ecuipment utilized to perform ISI examinations. The records includec: NDE equipment calibration and materials certification: and records attesting to NDE examiner qualification, ,
certification, and visual acuit ;
b. Observations and Findinas The inspectors noted during the contractor-performed MT examination of weld No.11301 001-13. that the contractor examiner removed excess >
3 articles from the examination area of interest during the examination :
'
'y a an oral airstream, This was contrary to procedure MT-V-50 Magnetic Particle Examination." Rev. 4. paragraph 10.7.1. which i required excess particles to be removed by a gentle airstream from an
! aspirator bulb. The concern was two fold: the force of an oral
'
airstream is not well controlled; and the possibility of introducing sputum into the examination area of interest could interfere with the '
examination. The licensee subsequently reviewed all MT examinations '
performed by the above examiner and reexamined the weld. The inspectors considered that the licensee took appropriate actions to determine the extent of the problem, correct the problem. and prevent recurrence. The licensee documented this issue in DC 1 79-562. In addition. the inspecti s noted that this failure constituted a violation of minor safety significance and consistent with Section IV of the NRC '
Enforcement Polic this was identified as Non-Cited Violation (NCV)
l 50 424/97-10 02, failure of Controctor Examiner to Follow MT Procedure.
i Except as noted above, ISI examinations observed / reviewed were conducted in accordance with approved pro,edures. by qualified and certified
,
examiners using certified / calibrated equipment and materials, i The licensee had implemented the containment inspection rule Repair and l Replacement (R/R) Program by issuance of GEN 25. Section !
- Repair / Replacement of ASME Code Class 1. -2-. 3. and MC Components.' and
[
Section 3.2. " Repair / Replacement of ASME Code Class CC Components."
l dated September 8.1997, and September 7,1997, respectivel Relative to Section 3.1 the inspectors noted that the repair of arc strikes was excluded from GEN 25 without regard to size or severit The licensee informed the inspectors that their program placed no requirements on the repair of arc strikes. This was of concern because *
Enclosure 2 ;
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16 h arc strikes can harbor minute cracks, porosity, hard zones and chemical !
heterogeneity. Despite their small scale. these conditions can trig t a major failure when they are located in an important stress field. ger !
The inspectors discussed this issue with the licensee, who indicated -
that they would look further in this matter and take appropriate actio r Conclusions l Except for the NCV related to failure to follow the MT procedure ISI activities observed / reviewed were conducted in accordance with !
.
procedures, licensee commitments and regulatory requirements. The licensee's programmatic coverage of arc strikes was considered a ;
.
weaknes M1.4 Steam Generator (S/G) Tubesheet Rework a.; Insoection Scone (73753) j On May 28. 1996, the Vogtle Unit I digital metal 1maact monitoring
- system (DMIMS) detected loosc parts in S/G # Wit 11n approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> the DMIMS indications were confirmed as loose parts. An object was located and removed from the channel head. A second object was -
lodged in the tube end at location Row 1 Column 115. Subsequent evaluation indicated the foreign objects to be from a guide tube sup) ort i pin. The ) arts removed from S/G #4 were the support pin nut and loccing device disc. A fragment of the support pin nut was removed from the cold leg. Remote visual examination confirmed that of the 5330 tube had from moderate local damage to heavy deformation of all tube end surface The procedures reviewed included: "Vogtle 1 Steam Generator (SG) #4 Engineering Evaluation of Tube To-Tubesheet Weld Region." dated March 1997: GP-16632. " Tube-to-Tube Weld Re) air Engineering Evaluation." dated June 10. 1997: GP 16636. SG l 4 Tube 3undle Integrity Assessment SECL."
dated June 18.1997: and ST0-FP_-1997-8050. " Tube Entry Rework in Model F -
Steam Generator Tubes at Vogtle Units 1 and 2." Rev. + Observations and Findinas Engineering evaluation indicated that the primary to secondary leaks were adequately prevented by the hydraulic expansioa of the tubes into ,
the tubesheet. The inspectors determined that the engineering evaluation was sound and comprehensiv Therefore, all that was required to address the damaged tubc end seal weld was to " rework" the tube ends by hard rolling. thereby assuring the subsequent cassage of eddy current probes. The licensee was in the process of hard rolling the 3612 tubes with moderate local damage to heavy deformation of all tube end surfaces. To evaluate the licensee's activities related to the l damage to the hot leg S/G #4 tubesheet, the inspectors interviewed
. licensee and contractor personnel, reviewed procedures and selected
. Enclosure 2
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17 l quality records, and observed work and work activities. Observations !
were compared with applicable procedures and the UFSA The procedure i was of good quality and personnel were appropriately trained and j qualified, [onclusions
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Unit 1 S/G #4 tubesheet rework activities were supported by appropriate evaluations, controlled by well written procedures, and highly trained :
and motivated individual F
M1.5 Guide Tube Suonort Pin (Solit Pin) Renlacement Insoection Scone (73753)
As a result of the May 28, 1996 DMIMS detection of loose parts in Unit 1 ,
SG #4, and their subsequent identification. the licensee elected to replace all the Unit 1 guide tube support pins (Inconel 750) with cold worked type 316 stainless steel pins. To evaluate the licensee's activities related to the guide tube support pin replacement, the inspectors interviewed licensee and contractor personnel, reviewed >
'
procedures and selected quality records, and observed work and work activitie The procedures reviewed included: DR No.9701, " Cold Worked 316 Stainless Ste^1 Realacement Guide Tube Support Pin, dated June 26, 1997, and EN 2.7.1 GAE/GBE 1. " Guide Tube Su GeneratingPlantUnits1and2.pportPinReplacementatVogtleElectric Rev.- Observations and Findinas
.
Specific activities observed included: cap screw untorquing; cap screw unscrewing: cap screw removal: guide stud installation: split pin removal: and lower guide tube installation. Work activities were accomplished consistent with the procedure, monitored and controlle Observations were compared with applicable procedures and the UFSA +
The procedure was well written and of good quality, Conclusion _S, Unit 1 split pin replacement activities were supported by a)propriate evaluations, controlled by well written procedures, and hig11y trained and motivated individual M1.6 ltoubleshootina Proaram Review (61726)
'
. Inspection Scone As a re ult of previously identified issues with the lack of a formal troubleshoot program, the licensee developed Procedure 10024-C, Enclosure 2
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- Equipment Troubleshooting." Rev. O. to facilitate troubleshooting efforts. During Unit I startup, the inspectors observed two troubleshooting activities which utilized Procedure J0024-C. The inspectors also reviewed the associated paperwor b. Qbservationsandfindinas
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During the performance of Procedure 14666 1. * Train A Diesel Generator and E6fAS Test " Rev. 5. slave relay K325 failed to energize. The failure of slave relay K325 prevented the aiping senetration filtration system f rom starting as designed. Using tle trou)leshooting techniques specified in Procedure 10024 C. slave relay K325 was removed and bench tested. No problems with slave relay K325 were identified during the bench test. Slave relay K325 was then placed back in service and monitored during the second performance of surveillance 14666-1. During performance of the second test, the relay operated correctl The inspectors observed a second troubleshooting offort during the p6rformance of hot rod drop tests. The DRPI for control rod M-2 malfunctioned which resulted in a manual reactor trip (reference Section 01.4). Using Procedure 10024-C. detailed directions were developed to determine that the indication malfunction was actually caused by the known failure of the data "B" coil. Control rod M 2 was succe:sfully withdrawn after placing the DRPl system in data 'A' only, c. Conclusions The inspectors concluded that during the trot.bleshooting activities, appropriate oersonnel from reactor engineering, operations. and maintenance departments were involved Work orders and temporary procedures were developed as needed and in a timely manner. The inspectors also concluded that the troubleshooting activities were performed in accordance with procedure 10024-C. * Equipment Troubleshooting." Rev. H3 Maintenance Procedures and Docunentation M3.1 Diesel Generator and ESFAS Testina (61726)
a. Inspection Sccae The inspectors observed performance of Diesel Generator and ESFAS testing as part of the safety-related surveillance startup testin This surveillance is conducted en a 18 month frequency. The procedures, acceptance criteria. briefing techniques and conmunications were reviewed or ubserved by the inspector Enclosure 2
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- QtservationsandFindinas !
The inspectors observed performance of Procedure 14665 1 " Train A !
Diesel Generator and ESFAS Test." Revision 5. Section 5.2. " Loss.0f- ,
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Offsite. Power (LOSP) In Conjunction With An ESF Actuation Test Signal Followed By 51 Actuation With The DG In A Test Mode:" Section 5.3 *DG !
Start on LOSP:" and Cection 5.4. "DG Start on SI Signal." The ,
inspectors reviewed results documented in tu completed procedure and !
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verified that test results met the acceptance criteria of each
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respective section. The inspector also reviewed the failed i component / test exception logs for both the A and B train ESFAS test and .
verified that test exceptions were retested or dispositio.. properl !
On October 8. Diesel Generator 1B failed to start during the performance !
of surveillance 14667 1. * Train B DG and ESFAS Test.' Section 5.2. The -
i licensee determined that the failure was due to revised procedural steps which resulted in the isolation of the control air from the DG auto-start circuit, thereby preventing the diesel generator from startin (Rc'er to Section 03.2.) The failure of DG 1B to start resulted in the 4160 KV IE essential electrical switchgear.1BA03, remaining .
de-energized. Operations shift personnel responded by re energizing i 1BA03 per abnormal operating procedure (AOP) 18031-C. " Loss of Class 1E i
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Elect 5/s. ' Rev. 15. Operations personnel performance of the AOP was ef ficient and affective,
' Conclusions
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The inspectors concluded that DG and LSFAS tests were performed in accordance with written procedures. The inspectors identified several minor administrative issues that were forwarded to the licensee and appropriately dispositioned. Overall. ti.' test activities observed were well controlle M3.2 Emeroency Core Coolino System Flow Test (61726) ECCS Subsystem Flow Balance The inspectors observed portions of the performance of Surveillance 14721-1. "ECCS Subsystem Flow Balance and Check Valve Refueling inservice Test." Rev. 1 The test verified I' low rates of each emergency core cooling system. The surveillance is performed on an 18-month frequency or at the completion of ECCS modification '
b, Observation and Findinas Prior ta IR7 the licensee revised Procedure 14721-1 which altered the test methodology and ultimately the acceptance criteria. Procedure i
14721 1. Revision 18. acceptance criteria was modified from a measured flow-based test to a calculated resistance-based methodology. A review .
rf a licensee performed safety evaluation indicated that the change to a ,
Enclosure 2 i
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resistance based acceptance criteria results in a less restrictive flow ban However, the new methodology was maintained consistent the UFSAR cccident analysis to ensure adecuate flow rates are achieved for each ECCS syste The new calculatec resistant based method used measured differential pressure of the system to calculate a system resistanc That resistance, which reflected system and aump performance. was used to calculate flow and determine system opera)ilit The inspectors observed the performance of Procedure 14721 2. Sections 5.1. 5.2. 5.4. and 5.5. These tests included a Centrifugal Charging '
Pump (CCP) cold leg injection: Safety injection cold leg injection:
Residual Heat Removal (RHR) cold leg injection; and RHR check valve test. The surveillance was performed successfully with the exception of section 5.1 which involved an issue with the test setup for CCP train
"A". The licensee determined after completion of section 5.1 that the measured discharge pressure for CCP train "A" was recorded from instrumentation that was incorrectl., located. The test setup did not reflect the proper configuration consistent with the new resistance-based program. Af ter installation of additional instrumentation. CCP train "A was tested and data collected indicated that the pump successfully met W.ablished performance criteria of the 14721-1 surveilianc Conclusion The inspectors did not identify any concerns with the new test methodology for the ECCS flow balance surveillance. Based on this review, the inspectors concluded that the test was performed in accordance with written procedures, was well controlled, and coordinate M8 Hiscellaneous Maintenance Issues (92902)
M (Closed) Unresolved item (URI) 50-424. 425/95-27-03: Proper Calibration of Reactor Irip System and ESFAS 1 rip Setpoints Inspection Scone (92902)
The inspectors 3reviously opened URI 50 424, 425/95 27-03. Proper Calibration of leactor Trip System and ESFAS Trip Setpoints. to document an issue concerning the licensee's adherence to inequality symbols stated in the TS Reactor Trip System (RTS) and ESFAS instrumentation I tables. The issue was opened pending NRC's review of the licensee's methodology. Based on NRR's conclusion with respect to the use of inequality symbols, the inspectors discussed the NRC's position on trip setpoints with IhC personnel and licensee maintenance department managemen Enclosure 2
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b. Observations and Findinas The inspectors identified a concern with the adherence to inequality -;
symbols (i.e.. greater than or equal to (t) and less than or equal to i (5)) associated with TS tables trip setpoints. Specifically, the !
inspectors identified that the licensee's calibration procedures did not :
strictly 3dhere to tSe symbols as stated in TS RTS and ESFAS tables i 3,3.1-1. " Reactor Trip System Instrumentation," and 3.3.2-1, " Engineered ,
Safety feature Actuation System Instrumentation." The concern was +
identified that. based Jn the licensee's calibration procedures, it was <
possible to calibrate an instrument and have its "as-left" setpoint-be outside the TS inequality values annotated in the TS tables
,
Based on the inspectors' review, it was determined that the Vogtle ~ l calibration procedures did not, in fact, establish calibration -[
procedures heeding the inequality symbols. The licensee provided !
documentation that stated that the Westinghouse setpoint methodology and .
Vogtle TS B6:es documentr, established trip setpoint values as " nominal" i values, Therefore, the Vogtle calibration procedures were maintained l consistent with those documents. However, the inspectors' review of TS indicated that trip setpoints had minimum or maximum values (inequalities) for each function. rather than trip setpoint " nominal" value The inspectors reviewed "as-left" calibration data sheets which indicated that the licensee did not take advantage of procedure tolerances, as such, no instrument trip setpoints were found to be beyond the TS " allowed values." In accordance with the TS Bases document guidarce, a Masured setpoint which does not exceed the
" allowed value," is considered operable. Therefore, because no instrument trip setpoint was left outside the "al' owed value" this issue had minimal safety significance.
.
However, a review of the I&C calibration procedures identified that ;
l approximately 83 procedures per unit would potentially set instruments outside the trip setpoint inequality values. Of the "as-left" calibration data sheets reviewed by the lkentee, approximately 30% were identified that did set instrument t"ip setpoints bejond the minimum or maximum values indicated in the TS table Based on review by the inspectcrs of those eta sheets, the inspecturs verified that not all instruments calibrated during the Unit 1 refueling outage were in accordance with the TS tables trip setpoints and the associated
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inequality symbols. As ; result, the licensee established administrative controls to limit the resetting of trip setpoints
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consistent with-the TS inequality values delineated in the IS RTS and ESFAS instrumentation setpoints tables, procedure 2t028 C, "RTS and
'
ESFAS Instrumentation Trip Setpoint Control " Rev. 2. was developed and t j implemented for plant personnel use on October 6. 199 >
Enclosure 2
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22 i c. Conclusions The calibration procedures identified that set the "as-left" instrument trip set)oints beyond the inequality values are contrary to TS RTS and ESFAS taales 3.3.1-1 and 3.3.21 values. However, consistent with i Section IV of the NRC Enforcement Policy this was identified as !
NCV 50 424. 425/97-10 03. Improperly Set RTS and ESFAS Trip Setpoint !
II Enaineerino ,
E2 Engineering Support of Facilities and Equipment -
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E Valve Modifications to Eliminate Pressure Lockina and Thennal B4ndino i
a. Insnection Scone (37551)
The inspectors reviewed licensee actions taken in response to NRC Generic Letter (GL) 95 07. " Pressure Locking and Thermal Binding of Safety Related Power-Operated Gate ValvesJ That review was documented in Inspection Report 50 424, 425/96 02. However, as part of that '
review, the inspectors evaluated a recent design change package (DCP)
implemented during the Unit 1 seventh refueling outage. This modification was im)1emented on the remaining Unit 1 valves determined .
by the licensee to 3e affected. The inspectors conducted field observation of a portion of the modification to 1 HV-8840. Residual Heat Removal (RHR) hot leg injection crossover isolation valve and a post-maintenance review of the completed work orde b. Observations and Findinos The licensee's evaluation in response to GL 95-07 identified eight valves including 1-HV-8840. in each unit for modification to provide additional assurances that the valves will be capable of performing their design basis function. The inspectors reviewed DCP 97-VIN 002 "RHR Hot Leg injection Crossover Valve Pressure Locking Prevention."
which modified this valve. This modification consisted of drilling a 1/8-inch hole through the down stream side of the valve disc thus 3roviding a vent )ath for any pressure trapped in the valve bonne ) rilling a small 1 ole in the disc of the valve provided a relief path to prevent the build up of pressure in the bonriet area, thereby precluding the possibility of pressure 1rcking for this valv The inspectors reviewed DCP 97-V1N0022 in dept As part of this review. the inspectors reviewed the TS: applicable portions of Updated Final Safety Analysis Report (UFSAR) Sections 5.4.7. 6.2.2. 6.3, and 15:
and the licensee's response to GL 95-07 dated February 8. 1996. The insp e -s also reviewed the 10 CFR 50.59 safety evaluation for the DCP and v died that the safety evaluation considered items such as the Enclosure 2
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impact on leakage, inservice inspection / Inservice Test (ISI/IST)
program. leak rate testing seismic and environmental qualification, and valve seating. The inspectors concluded that DCP 97-VIN 0022 wos ared in accordance with applicable licensee procedures. The 10 CFR pre 50 $9safetyevaluationprovidedthetechnicalbasisthattherewasno unreviewed safety n" c ico associated with this DC Conclus1201 The inspectors concluded that the DCP package was complete and
- sufficiently detailed, and implement 3 tion of the valve modification was
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satisfactory.
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E3 Engineering Procedures and Documentation E3.1 APEX User Manual Review
! Insnection Stone (9290M As documented in Inspection Report 50-424, 425/96-11. the licensee experienced diffir'11 ties in performing an Estimated Critical Position (ECP) using the APEX computer code for a core with less than ten days burnup history available. To ]rovide more explicit guidance, the '
licensee proposed changes to t1e APEX users manual to include:
additional guidance on calculations for low burnup cores: determining average control rod position and average power during periods of zero power oaeration: the number of significant digits and when zero can and cannot )e used: and deterinining proper time periods and burnup for core dealetion history, reference point, and shutdown time for input into APE These corrective actions were considered as mitigating factors in identifying this issue as NCV 50-425/96-11-04 Inaccurate Calculation of Estimated Critical Condition. The inspectors reviewed Rev. 4 of the APEX users manual to determine the effectiveness of the corrective actions and if the corrective actions fully addressed the deficient conditions identified. The inspectors also interviewed qualified reactor engineers to ascertain the usefulness of the rev'. sed manual if a reactor trip occurred with less than 10 days burnup history. This review was performed prior to startup of Unit 1 from the seventh refueling outage, Observations and Findinas Based on the review of Rev 4 of the APEX users manual, the inspectors determined that the Licensee's corrective actions were not adequate in that the APEX users manual was not revised to include all the identified corrective action In addition, training that the licensee conducted on the use of APEX code provided additional guidance that was not Enclosure 2
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described in the APEX users manual, and in some uses, contradicted guidance included in Rev. 4 of the APEX users manual. Specifically. the inspectors identified that the APEX users manual permitted zero to be used as an input value for reactor power, but the training indicated that zero could not be used for conditions with less than ten days "
burnup history or incorrect results would bc obtained. Instead,the training indicated that a "small number" would have to be substitute The APEX users manual cautioned that entering small positive values may result in negative burnup values producing incorrect results. The APEX computer code did not provide an error check for negative burnup values and provided no guidance on what constituted a "small number."
Additionally, during a demonstration of APEX by a qualified reactor engineer, the inspectors observed that the reactor engineer had to rely on training handouts in order to obtain accurate result Conclusions The inspectors determined that the APEX manual had not been sufficiently clarified to include additional guidance necessary to ensure an accurate ECP can be determined after a reactor trip for a core with less than ten days burnup history. The licensee failed to incorporate adequate corrective actions in Rev. 4 of the APEX users manual prior to the restart of Unit 1. This is a violation of 10 CFR 50 Appendix B Criterion XVI and is identified as VIO 50 424/97-10 04 Failure to Ta..e Adequate Corrective Actions to Revise the APEX Users Manua E8 Hiscellaneous Engineering Issues (92903)
E (Closed) LER 50-424/96-005. Rev. 1: Unqualified Cabling Used in Containment Sump Level Transmitters Insnection Stone (92902)
The inspectors reviewed LER 50-424/96-005 Rev.1. Unqualified Cabling used in Con +ainment Sump Level Transmitters, associated Maintenance Work Orders (MWOM, Deficiency Cards (DCs), site drawings, and plant procedures. Those items reviewed are listed below:
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Procedure 00057-C, " Event Investigation," Rev. 10
- Procedure 00058-C, " Root Cause Determination," Rev. 11
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Procedure 81030-C. " Preparation and Processing of Draft Licensee Event Reports and Technical Specification Reports." Rev. 2
- AX3D-AA-A00V-01. " General Notes Installation Instructions, and References for Cable Splices," Rev, 2
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AX3D-AA-A00V 02. " Notes and Details for In-Line Cable Splices "
Rev. 3
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AX3D-AA-A00V-03. " Notes and Details for In-Line Bolted Cable Splices," Rev. 2
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AX3D-AA A00V-04, "Three-Way, Four-Way & V Cable Splices Details "
Rev. 2 Enclosure 2
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i Observations and Findinas i i
The inspectors reviewed LER 50 424/96 005. Rev. 1. including the I corrective actions developed. The licensee was unable to determine a root cause of the event due to a lack of documentation available of the maintenance and the length of time since the maintenance was accomplished during construction of Unit 1. It was determincd that ,
these instruments do not perform an active function in mitigating the consequences of an accident, and that other instrumentation was available to determine containment water level. Actions to address the .
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LER corrective actions were completed and properly documented. Training '
adequately addressed the issue. However, the licensee *s review was limited in scop A " broadness review." as defined in Vogtle Electric Generating Plant (VEGD) Procedure 00058 C. is "A review... to determine if this type of occurrence could impact other trains, channels. components. or similar processes on either unit..." The broadness review for LER 50 424/96-005 concentrated on the containment sump level transmitters and, therefore, only these splices were inspected. In this LER there were two identified problems. The first was that the sump level transmitter splices were not environmentally qualified because the outside jacketing had been removed. Secondly, unjacketed splices were installed in covironmentally unqualified junction boxes. Since the broadness review concentrated on the affected components it failed to identify the improper installation and repair of Eaton cable splices in other applications. Consequently. the full scope of unqualified splices used in the plant was not identified. Additionally, the review did not identify a similar issue which occurred during construction. It was not until additional examples of unqualified splices were discovered that ,
the licensee expanded the scope of their corrective actions (see LER 50-424/97 004. " Unqualified Cables Renders Atmospheric Relief Valves Inoperable.")
Based on this broadness review, the licensee looked more at components than processes (i.e. looked at other sump level transmitters for faulty ,
splices rather than sample different component splices). Licensee personnel stated that focusing the review was done in an effort to ensure a manageable sample size and appropriately apply resource Conclusions The corrective actions committed to in LER 50-424/96 005 have been ,
complete The inspectors determined that the review conducted for LER 50 424/96 005 was of limited scope and did not identify that the Eaton cable splicing issue exte :1ed beyond the containmeat sump level transnitters. However. the broader implications were recognized and addressed in LER 50-424/97-004. Unqualified Cables Renders Atmospheric Relief Valves inoperable. LER 53-424/96-005 is close ,
Enclosure 2
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E8.2 (Closed) LER 50 424/97-004: Unqualified Cables Renders Atmospheric kelief Valves-Inoperable
, Insoection Stone (92902).
The inspectors reviewed LER 50-424/97 004. Unc;ualified Cables Renders I Atmospheric Relief Valves inoperable, associated MW0s. DCs. site :
drawings, and plant procedures. Those items revicwed are listed below:
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Procedure 25718-C. " Heat Shrink Insulation for Control and Power Cable Splices and Terminations." Rev. 17 t
- Procedure 85016 C. *0uality Control Monitoring," Rev. 6
- Specification X3AR01-E9. " Cable Wiring Installation and ,
Connections." Rev. 32
- - AX3D-AA A00V-05. " Grey-Body Cable Splices " Rev. 3
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AX3D AA A00V-06 " Transition Cable S lices." Rev. 2 i
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AX30 AA A00V-07 " Transition Cable S lices." Rev. 3
- AX60042. * Instruments Requiring Qual fication for Harsh Environment." Rev. O The inspectors also observed licensee personnel conduct inspections of a -
sample population of Eaton cable splices, Observations and Findinas
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In LER 50 424/97-004, the licensee stated that there were no previous similar events. However, the licensee's broadress review identified DCs associated with LER 50 424/96-005. Rev. 1. as being examples of the same issue: specifically improper Eaton cable transition splice Additionally. the Training Department review and subsequent lesson outline (MA LP-97007-00) laentified this as a similar issue. Although LER 50 424/97-004 did not specify LER 50-424/96 005. Re. 1. as a similar issue, the corrective actions and follow-up sampling would not have changed significantly if it was identified as a similar issu l The licensee conducted a root cause irvestigation of this event and was unable to determine why the splices were improperly installed. An evaluation of the splice installations identified in the LER was conducted by contract personne The specific splices were determined to be environmentally qualifie Three of the four correr41ve actions for LER 50-424/97-004 were completed and appropriately documente The i fourth corrective action, a broadness review temained open, due to open items within the corrective action, although th broadness review was t completed, The broadness review included a plan to sample 80 splices (40 oer unit) during the upcoming Unit 1 and Unit 2 refueling outage >
At th time of this inspection the Unit 1 sampling was in its initial stages. The inspectors observed four satisfactory ins)ections on September 25, 1997: two others were already completed )y the licensee and were determined to be satisfactory. Prior to the end of the i inspection period the licensee completed the sampling on Unit No Enclosure 2 ,
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i 27 r improperly spliced cables were identified within the scope of the progra However, six splices, outside the sam) ling scope, were !
identified as not meeting the requirements of tie installation dr3 wing The instrumentation affected by these six splices was not required to !
function or required to provide indication dur'ng post-accident conditions. The inspectors determined this is;ue to be a com)liance issue with the construction drawings oniv The licensee's LER commitmentwillremainopenthroughthe$p. ring 1998 Unit 2 refueling outage in order to track these sampling result Conclusions The irispector concluded that the corrective actions for Unit I were completed. Based on this review LER 50 424/97-004 is closed. To evaluate the Unit 2 inspection sampling program. Inspector Follow Up Item (IFI) 50-425/97 10-05. Unit 2 Eaton Cable Splice Sampling, was opene E8.3 Maintenance Rule lmolementation ,
. Inspection Scone (92902).
During the inspection of corrective actions for LER 50 424/96 005. Rev.
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1. and LER 50-424/97 004 Maintenance Rule implementation was also evaluated. MW0s. DCs. event investigations, root cause analysis. and plant procedures concerning Mainteance Rule implementation, were reviewed. Those items reviewed are listed below:
- Procedure 00150-C. " Deficiency Control," Rev. 23
- Procedure 00353 C, " Maintenance Rule implementation." Rev. 4
- Procedure 50028-C. " Engineering Maintenance Rule implementation."
Rev. 5
- Procedure 80014 C. " Handling of Deficiency Cards." Rev. 11
- Procedure 81030-C. " Preparation And Processing Of Draft Licensee Event Reports And Technical Specification Reports." Rev. 2 Observations and Findinas
- During the inspectors' review of LER 50-424/97-004, an issue involving the Maintenance Rule was raised, regarding DC 1-97-173. The associated Root Cause and Corrective Action (RCCA) report was not appropriately completed. in that, the question concerning the determination and documentation of the event classification as a Maintenance Preventable Functional Failure (MPFF) was not answere The l1censee opened DC 1-97 561 te address this specific issu DC 1-97-173 and other DCs associated with the RCCA (DC 1-97-126 and DC 1-97-132) were subsequently reviewed and determined to not be MPFFs. Additionally, the licensee reviewed approximately 75 RCCAs from the same time period and identified no other instances where MPFF determinat~ ins were not completed. The i MPFF evaluations for DC 1-97-173. DC 1-97-126. and DC 1-97-132 were Enclosure 2
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28 delayed approximately 4 months, which caused untimely MPFF determination The prc:ess uses a variety of procedures to ensure that deficiencies are reviewed against the MPFF criteria. However, based on the inspectors'
r2 view, it was difficult to ascertain who was responsible to ensure that items or issues identified on DCs related to LERs were reviewed to determine if thcy represented an MPF In the case of an LER, the DC procedure also sends the individual to the draft LER procedure which is done in series with the DC process. The draft LER procedure does not reference the '*intenance Rule. In the deficiency control procedure, itis implied tnat it is up.to the final review by Nuclear % < and Compliance personnel and the responsible department manager , ,1dentify and document MPFFs. This process deficiency could cause delays in determining whether a system was required to be placed in the Maintenance Rule (a)(1) category, Conclusions The inspectors concluded that the process to document and determine if an LER 1ssue qualified as an MPFF is weak in that it does not ensure timely determinations, nor is it clearly proceduralized. In addition, the res)onsibility to document and determine if an LER issue qualified as an M)FF is also not clearly proceduralized. Although the specific examples of untimely MPFF determinations were not safety-significan the lack of clear guidance for MPFF determinations in the area of the deficiency card review process was identified as a weaknes IV. Plant Support R1 Radiclogical Protection and Chemistry (RP&C) Controls
- Rl.1 Lower Guide Tube Removal Activity
' Inspection Scone (71750)
The inspectors reviewed the licensee's preparacions and implementation of the activities to remove a damaged lower guide tube from inside contair"nent . The inspectors reviewed the health physics radiological surveys, a safety evaluation for movement. storage, and restraint of the lower guide tube cask. Procedure (Chet Juclear Systems) TR-0P-045-4290 " Handling Procedure For Irradiated Hardware Shipments In The FSV-1 Cask " Revision (Rev.) 1. and various lower guide tube vendor drawings.
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29 Qttservations and Fint.n_qi n
The licensee determined that the lower guide tube would be removed due to suspected damaged caused when a control rod shaft was dro) ped from approximately six feet above the upper guide top opening. T7e licensee termined that both the drive shaft and guide tube were required to be
!"noved and replaced to ensure integrity of the upper internals
.mponent ;J The radiological surveys completed prior to removal of the lower guide it tube from the reactor cavity ind ated the highest Jose rate at 686
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Rem / hou In preparation for removal of the guide tube the licensc2 took the appropriate radiological precautions necessary in hanoling an item with excessively high dose rates. Lead shielding was placed in certain areas in containment to protect workers from exposure to the guide tube as it was raised out of the reactor cavity. In addition, personnel access to containment was strictly limited by health protection management to only essential personnel during the removal activitie On October 13, 1997, the licensee performed removal and storage activities of a lower guide tube from inside containment. Removal and storage activities were well controlled, coordinated, and in accordance with the vendor procedure. The lower guide was removed and stored inside a cask without incident. Due to the shielding provided by the cask survey measurements indicated that the dose rates were reduced to approximately less than 10 mrem / hou Conclusions The inspectors concluded that the waval and storage activities for the lower guide tube were well control, e coordinated. and in accordance with the vendor procedure. Worker precautions were appropriate. The licensee's awareness cr "adiological and personnel safety associated with this activity was identified as a strengt R3 RP&C Procedures and Documettsiir R3.1 Contaminated Worker leaves Site Unaathorized Jninection Scene (71750)
The inspectors reviewed the circumstances surrounding the self-decnntamination activity performed by a Westinghouse contract employee on October 3. 1997. The inspet cors reviewed the licensee's Procedure 00930-C. " Radiation and Contar nation Control." Rev. 15. and Procedure 00920-C. " Radiation Exposure Limits and Administrative Guidelines." Re . the deficiency card generated, personnel statements, and the health protection department's dose equivalent calculation for the exposed individual. In addition, the inspectors discussed the event with Enclosure 2
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licensee health protection managemen Observations and Findinas On October 3.1997 health protection personnel received a call from a regarding an alarm on a gamma portal monitor located at the A'terna;e Plant Em)loyee Security Building (APESB). A review of the sequ a e of events, Jased on collected personnel statements, were as follows: an Y employee entered the APESB: stepped into a gamma portal monito " alarmed" the gamma portal monitor; proceeded over to the secutity badge island to speak with a security officer: employee was told to wait for health protection assistance by security officer: employee went outside the AMSB: removed his shoes and socks: put his shoes back on: stepped into the gamma portal monitor (a second time): received a " cleared" signal; exited the protected area: and left the site. The socks were retrieved by a health protection representative. The socks were subsequently surveyed and determined to have a " discreet particle" measuring approximately 40.000 dpm/ probe are The licensee informed the inspectors that it was determined that the contractor most likely picked up the discreet particle while inside containment in and around the steam generator platforms. No other incidents of discreet particles were identified Nring the outag The dose equivalent calculation performed by the licensee determined that a maximum exposure (total dose) to the individual was approximately 1529 mrem. This calculation was based on the assumption that the particle was on the employee's sock for the employee's entire shift (i.e., 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />). Through further investigation. the licensee was able to identi Q the employee involved in the radiological inciden The inspt d ers ure informed that the employee's badge access was terminated on OctuN o 199 Procedure v0930-C establishes the requirements and responsibilities for monitoring and controlling exposure to radiation and contaminatio Procedure 00930-C requires that health protection personnel to be immediately notified whenever contamination is detected on any individual or their personal articles. Plant personnel are not to perform self-decontamination without health protection personnel presen Conclusions On October 3. a contract employee performed self-decontamination without the assistance of health protection Jersonnel. A'ter alarming a gamma portal monitor the employee removed lis socks. " cleared" the monitor, and subsequently left the site unauthorized. The inspectors concluded that the action by the contract employee wa.t contrary to the requirements of Procedure 00930-C. The licensee's corrective actions were adequate and the subject employee was terminated from further employment at the plant. Consistent with Section VII of the NRC Enclosure 2
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Enforcement Policy this was identified as NCV 50-424/97-10-06. Improper Self-Decontamination by Contract Employe Manaaement Meetinas and Other Areas X Review of Updated Final Safety Analysis Report (UFSAR)
A recent discovery of a licensee o]erating its facility in a manner contrary to the UFSAR description lighlighted the need for a special focused review that conipares plant practices, procedures and/or parameters to the UFSAR descriptions. While performing the inspections discussed in this re] ort the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameter X1 Exit Meeting Summary The inspectors 3 resented the inspection results to members of licensee management at 11e conclusion of the inspection on November 4. 1997. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie PARTIAL LIST OF PERSONS CONTACTED licenseg J. Beasley. Nuclear Plant General Manager J. Gasser. Plant Operations Assistant General Manager B. Burmeister. Manager Engineering S. Chestnut. Manager Operations K. Holmes. Manager Maintenance t 1. Kochery. Superintendent Health Physics Department M. Sheibani. Nuclear Safety and Compliance Supervisor C. Tippins. Jr.. Nuclear Specialist 1 Enclosure 2
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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 73753: Inservice Inspection IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering ITEMS OPENED AND CLOSED Onened Typ3 Item Jumber S_tAtyji Descriotion and Reference VIO 50-424/97-10 01 Open Mis-Positioned Unit Heater Breakers on 480-volt MCC INBG (Section 02.2)
NCV 50-424/97-10-02 Open Failure of Contractor Examiner to Follow MT Procedure (Section M1.3)
NCV 50-424. 425/97-10-03 Open Inproperly Set RTS and ESFAS Trip Setpoints (Section M8.1)
V10 50-424/97-10-04 Open Failure to Take Adequate Corrective Actions to Revise the APEX Users Manual (Section E3.1)
IFI 50-425/97-10-05 Open Unit 2 Eaton Cable Splice Sampling (Section E8.2)
NCV 50-424/97-10-06 Open Improper Self-Decontamination Performed by Contract Worker (Section R3.1)
C101ed V10 50-424/97-04-01 Closed Containment Debris identified During IP1 (Section 08.2)
VIO 50-425/96-11-02 Closed luproperly Performed Surveillance to Closecut Unit 2 Containment (Section 08.2)
IFI 50-424. 425/97-08-01 Closed Resolt: tion of Self-Assessment Findings (Section 08.3)
Enclosure 2
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LER 50-424/97-006 Closed Hydrogen Monitoring System Train Rendered Inoperable (Section 08.4)
NCV 50-424/97-10-02 Closed Failure of Contractor Examiner to Follow MT Procedure (Section M1.3)
NCV 50-424. 425/97-10 03 Closed Improperly Set RTS and ESFAS Trip Setpoints (Section M8.1)
UDI 50-424. 425/95-27-03 Closed Proper Calibration of Reactor Trip System and ESFAS Trip Setpoints (Section M8.1)
LER 50-424/96-005-01 Closed Unqualified Cabling Used in Containment Sump Level Transmitters (Section E8.1)
LER 50-424/97-004 Closed Unqualified Cables Renders Atmospheric Relief Valves Inoperable (Section E8.2)
NCV 50-424/97-10-06 Closed Improper Self-Decontamination Performed by Contract Worker (Section R3.1)
Enclosure 2
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