IR 05000327/1997017
| ML20199G078 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 01/16/1998 |
| From: | Lesser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20199G059 | List: |
| References | |
| 50-327-97-17, 50-328-97-17, NUDOCS 9802040208 | |
| Download: ML20199G078 (31) | |
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U.S. NUCLEAR REGULATORY. COMMISSION !
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Docket Nos: 50-327, 50-328
" License Nos:- DPR-77,:DPR-79-
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- - Report No: 50-327/97-17. 50-328/97-17
Facility: Sequoyah Nuclear Plant, Units 1 & 2
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- Location: Sequoyah Access Road Hamilton County, TN 37379
! Dates: November;9throughDecember.20,1997 i
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- Inspectors: Shannon, Senior Resident Inspector
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R. Starkey. Resident-Inspector
, W. Bearden, Reactor Inspector, Region II,
! (Sections M1.8, M2.1, M2.2, M2.3, M8.10, M8.11. and
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W Holland. Reactor Inspector _ Region-II, (Sections M1.7 and E8.6)-
- W.'Kleinsorge, Reactor Inspector, Region II, .
(Sections M1.5 and M1.6)
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D. Rich, Resident Inspector, Watts Bar
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f Approved by: M. Lesser, Chief Reactor Projects Branch 6 Division of Reactor Projects L-
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- Enclosure 9eo204o20e 980116 PDR ADOCK 05000327
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l EXECUTIVE SUMMARY Sequoyah Nuclear Plant. Units 1 & 2 NRC Inspection Report 50-327/97-17. 50-328/97-17 ulis integrated inspection includos aspects of licensee operations, maintenance, engineering, plant support, arid effectiveness of licensee controls in identifying, resolving, and preventing problems; in addition, it includes the results of a maintenance and material condition inspection, a maintenance rule followup inspection, and an inspection of the inservice inspet. tion program.
Doerations
Both units operated at power during the period. Operations was considered to be good (Section 01.1).
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A non-cited violation (NCV) was identified for failure to adequately review a hold order clearance which resulted in an unplanned volume control tank (VCT) level decrease. An additional clearance problem is discussed in Section M1.5 (Section 01.2).
Maintenance
. In general the conduct of maintenance and surveillance activities was considered to be good (Section M1.1).
A weakness in the pressurizer master pressure controller calibration procedure was noted for not ensuring proper operation of the setpoint dial (Section M1.2).
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A weakness was identified for not hcving a preventive maintenance program in place to )eriodically refurbish ASME Class 2 and 3 Section XI relief valves which 1as resulted in undetected setpoint drift problems.
(Section M1.3).
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An NCV was identified for failure to meet procedural requirements for work control and clearance control that led to an auxiliary building isolation (ABI) actuation signal and the temporary loss of a significant number of plant radiation monitors (20) and recorders (10) (Section M1.4).
- Inservice inspection activities observed / reviewed were conducted in accordance with procedures, licensee commitments and regulatory requirements (Section M1.5).
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The-licensee's-inability tonondestructive NDE) procedureexamination (produce qualification was considered records support a weakness in the licensee's nondestructive examination program (Section M1.5).
- The. licensee's inadequate review of visual acuity certificates was considered a weakness in the-licensee's nondestructive examination program (Section M1.5).
- The unclear linkage of traceability-for ultrasonic testing (UT)
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calibration standards was considered a negative finding in the l icensee's nondestructive examination program (Sec+ M1.5).
- The licensee had implemented the Containment. Inspection Rule in a satisfactory manner (Section M1.5). ,
- The licensee's actions, reviewed by the inspectors, to address the failure of 2-FCV-6-166A. the lower flow control valve from' feedwater heater 2C4 to feedwater heater 2C5. were appropriate and consistent with 10 CFR'50.E5 (Section M1.6).
- The licensee's processes for taking into account the total. impact on plant safety before taking equipment out of service for monitoring or preventative maintenance was adequate, Observed plant housekeeping and material condition was good. Improvements were noted in the performance of radiation monitoring system components (Section M1.7).
- Numerous corrective actions-had been identified during the licensee's =
evaluation of Emergency Diesel Generator (EDG) reliability. (Section M2.1)
- A weakness was identified with trending of EDG performance data. The licensee's trending program for the ED3s did not provide sufficient historical information to support identification of-degraded engine performance (Section M2.2)
e Several oil leaks were noted on the EDGs including one lube oil leak that will require partial engine disassembly to repair. The inspector determined that the identified leakage would not require immediate repairs. (Section M2.3)
Encineerino e The inspectors determined that the licensee promptly identified and followed up the Unit 2 fuel misload event and ensured the cause was found and corrected. (Section E7.1)
- The Management Review Committee demonstrated good safety sensitivity toward conditions adverse to quality and assurance that the scope of review of issues and apparent causes was broad (Section E8.6).
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ReDort Details Summary of Plant Status Unit 1 operated at full power for the entire inspection period.
Unit 2 began the inspection period at approximately 69% power and was increasing power to 100% following completion of the cycle 8 refueling outage.
The unit reached 100% power on November 10 dnd operated at "ull power for the remainder of the inspection period.
Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments yhile 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.
I. Goerations 01 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707. the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was considered to be good. with the exception of the inadequate clearance on the reactor coolant ietdown filter discussed in Section 01.2.
01.2 Inadeauate Clearance Review Results in Volume Control Tank (VCT) level Decrease a. Insoection Scooe (71707)
The inspector reviewed the circumstances which resulted in an unplanned 3% level decrease (approximately 120-150 gallons) in the Unit 1 VCT.
b. Observations and Findinas On November 21,1997, a Unit 1 reactor coolant system (RCS) filter was tagged out for filter replacement using hold order 1-H0-97-3951. The hold order, as originally written, contained -three valves (the filter inlet, out'let and bypass valves) to isolate the filter for replacement under work order (WO) 97-003729. Prior to issuance of the hold order clearance, a fourth valve. an RCS letdown drain valve was added to the clearance. The additional valve was ap)arently added to ensure isolation of the filter vent valve whic1 was to be rebuilt and was an addition to the original sco)e of the WO. The letdown drain valve is a normally closed valve, but t1e clearance incorrectly directed that the
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2 valve be placed in the open position. When the clearance was issued, with the four valves in the Jositions directed by the clearance, makeup automatically initiated to t1e VCT due to decreasing water level caused by the open drain valve. After reviewing flow diagrams, operations management directed the auxiliary unit operator (AU0) to close the letdown drain isolation valve. According to the control room logs, the drain valve had been oper for a) proximately five minutes. PER No.
S0972614PER. which documented tie event, estimated unat 120-150 gallons of water had drained from the VCT to the drain system during that five minute period.
The licensee's investigation failed to determine who added the fourth valve. Additionally, neither the personnel reviewing the hold order nor the control room operators questioned why the letdown drain valve was tagged open rather than closed. The correct position would have been for the valve to be tagged closed. The )rimary responsibility for ensuring hold order accuracy resides wit 1 operations personnel in the work control center (WCC), who write and review hold order clearances.
The licensee counseled and disciplined the appropriate personnel and initiated a required reading document for all operations personnel
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describing the event and reenforcing operations expectations for clearance reviews and pre job briefings for clearance placement.
Site Standard Pract Me (SSP)-12.3, Equipment Clearance Procedure.
Revision 14. established the process to provide protection for personnel and-plant equipment during operation, maintenance, and modification activities through the use of clearances. Contrary to SSP-12.3 hold order 1-H0-97-3951 did not provide protection for plant equipment during a maintenance activity, which resulted in an unplanned level decrease in the Unit 1 VCT. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-327/97-17-01).
c. Conclusions One non-cited violation was identified for failure to adequately review a hold order clearance, which was incorrect and resulted in an unplanned VCT level decrease.
01.3 Review of Overhead Lifts Durina Unit 2 Cycle 8 Refuelino Outaae a. Insoection Scoce (71707)
The inspector reviewed the program for performing overhead lifts of heavy components above safety related structures. -The review included observations of lifts in progress and a review of licensee evaluations performed prior to any heavy load lift over safety related structures.
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b. Observations and Findinas The inspector noted that lifts of heavy loads are controlled by Site Standard Practice 3rocedure SSP-6.6. Safe Practices For Operation Of Overhead Handling Equipment. Revision 4. Section 3.6.6. Control of Heavy Loads. provides guidance, in accordance with NUREG-0612. for administrative control of heavy load lifts. This section noted that safe load paths have been established, load handling )rocedures have been developed and requires that the Plant Operation Review Committee approve any deviations from the defined safe load paths. In addition.
Appendix V 3rovides guidance for performing high-hazard lifts and documents tie signoffs for approvals. inspections and prerequisites.
During the Unit 2 refueling outage the inspectors did not identify any outside lift activities above safety related structures. In addition, the inspectors discussed lift activities with the Operations Shift Manager and noted that no lift activities above safety related structures were in progress or had been completed.
c. Conclusions The inspectors concluded that heavy load lift activities conducted during the Unit 2 Cycle 8 refueling outage met the procedural guidance documented in SSP-6.6.
08 Miscellaneous Operations Issues (92901)
08.1 (Closed) UB1 50-327. 328/96-09-01. Determine Whether TS 3.3.1.1 Allow One Pressurizer Pressure Channel to be Bvoassed at the Same Time that a Second Pressurizer Pressure Channel is 1ricoed. The inspectors, after discussion with the NRC Office of Nuclear Reactor Regulation (NRR) and NRC Region II management, agreed with the licensee's determination that one )ressure channel may be bypassed and considered inoperable for up to six lours, at the same time that a second channel is ) laced in the tripped condition and considered to be operable. Wit 1 the bypassed channel considered inoperable and the tripaed channel considered operable. the minimum channels operable (tiree) TS requirement is still met. With respect to the evolution involving filling the reference leg.
the licensee successfully completed the activity in approximately two hours and all channels were returned to normal. The inspectors concluded that the licensee did not violate the LCO.
08.2 (Closed) VIO 50-327. 328/97-01-01. Failure to Maintain Adecuate Emeraency Diesel Generator Alarm Response Procedures. The inspector verified the corrective actions described in the licensee's response letter, dated April 17. 1997, to be reasonable and complete. A review of annunciator response procedures (ARP), which was committed to in the response letter, was performed with approximately 2045 annunciator windows reviewed by operations personnel. The licensee concluded that, based on the number and type of comments received. there was no indication that the quality review process associated with ARPs was inadequate. However, during the licensee's ARP review, comments were
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received on 169 ARPs identifying the need for specific / detailed guidance and suggested enhancements. A corrective action item, associated with PER No. SQ970370PER and scheduled to be completed by February 7, 1998, was initiated to revise ARPs to include adequate direction for the operating staff. AttacheJ to the PER was a list of the ARPs to be revised.
08.3 (Closed) VIO 50-327/97;'14-03. Failure to Follow Procedure for Exceedina Fuel Preconditionino Limitations. Not Loaaina Chanaes in Plant Conditions. and Not Informine the Shift Manaaer of Chanaes in Plant Conditions. lhe inspector verified the corrective actions described in the licensee's response letter, dated July 21, 1997, to be reasonable and complete. No similar problems were identified.
08.4 fClosed) URI 50-327/97-04-04. Further Review of Potential Reaulatory Lssues Noted in the Unit 1 Ooerational Loas. The inspector reviewed the identified refueling outage related operational problems documented in the control room logs during the Unit 1 refueling outage. No new regulatory issues were identified during the review, however: the inspector noted that the control room logs had not prov1Jed sufficient
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information to make that determination. Subsequently, detailed information was provided by the operations shift mant.gers to resolve this concern. Based on previous problems with documentation in the control room logs (EA 97-232), the licensee was aware of the weakness in this area and improvements were being implemented and/or planned. Based on the inspectors review this item is closed.
08.5 (Closed) EEI. 50-327.328/97-13-01. 02. 03. 04 On December 8.1997, the NRC issued three violations which together represented a Severity Level III problem, with a $55.000 civil penalty, for issues associated with a failure to realign a spare vital battery.
These issues were documented in NRC Inspection Report 50-327.328/97-13.
Accordingly, four Escalated Enforcement Items (EEIs) were closed, and licensee corrective actions will be reviewed in response to the three escalated enforcement (EA) violations opened per EA 97-409.
II. Maintenance M1 Conduct of Maincenance M1.1 General Comments a. Insoection Scooe (61726 & 62707)
Using inspection procedures 61726 and 62707, the inspectors conducted frequent reviews of ongoing maintenance and surveillance activities.
The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillances:
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. TI-52 Special Instruction for Removing the SSPS from Service and Returning It to Service.
. WO 97011026 Calibrate Auxiliary 011 Pump Control Switch on CCP 2A-A
. 0-PI-EBT-082-238.4 Modified Performance Testing of 125 Vdc Diesel Generator 8atteries (System 82)
. SI-102 M/M Diesel Generator Monthly Mechanical Inspections - EDG 2A-A
. 2-SI-ICC-068-320.3 Channel Calibration Of Pressurizer Level Channel Ill Rack 9 Loop L-68-320 (L-461)
. WO 97012267 Pressure Test for Pressurizer Level Transmitter SON-2-LT-068-0320
. 0-SI-0PS-068-297.0 Pressurizer Heater Capacity
. WO 97008408 Adjust Stroke of RCS Loop 2 Pressurizer Spray Line Control Valve b. Observations and Findinas The inspectors noted that, in most cases, the work activities and the performance of the surveillance activities were adequately performed.
4hile observing various activities and/or by reviewing control room logs, the inspectors noted some instances where deficient conditions occurred during surveillance activities, c. Conclusions In general the conduct of maintenance and surveillance activities was considered to be good with exceptions noted in the following sections.
M1.2 JmoroDer Maintenance Activities Associated With Reolacemen* Of The Pressurizer Master Pressure Controller a. JmrectionScoce(62707)
The inspector reviewed the maintenance and post modification activities associated with the replacement of the pressurizer master pressure controller, b. Observations and Findinos While reviewing the control room logs, the inspector noted that when the licensee placed the pressurizer master pressure controller in service, the spray valves opened when the pressure setpoint was increased and the pressurizer heaters came on when the pressure setpoint was decreased.
The operators noted the deficient operation of the controller and
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initiated a work request. The inspector reviewed the maintenance, post modification and troubleshooting activities associated with the improper installation and testing of the controller.
The inspector noted that during the Unit 2 Cycle 8 outage, the 3ressurizer master pressure controller was replaced. The outdated r
oxboro controller was subject to a reset windup condition which had the potential to cause operational difficulties. A design change was im)lemented to replace the controller with a control unit that was not su) ject to the reset windup condition. The controller was setup according to plant procedures, however, the procedures did not verify proper o)eration of the setpoint adjustment controls. During troubleslooting, the licensee noted that the controller dial was operating in reverse. This condition was the result of having two jumpers reversed in the controller.
The licensee concluded that the post modification testing procedure did not adequately address the operation of the setpoint dial on the new controller. The licensee determined that the revisions to the pressurizer pressure calibration procedures were recessary to ensure that the setpoint dials were adequately verified. The licensee also noted that other control room controller calibration procedures would be reviewed and revised as necessary to ensure proper calibration of any setpoint dials.
c. Conclusions A weakness was noted, with the calibration procedure for the pressurizer master pressure controller, for not ensuring the proper operation of the setpoint dial.
M1.3 Lackina Periodic Relief Valve Refurbishment Proaram a. Insoection Scooe (62701)
The inspector reviewed the licensee's root cause investigation report concerning the failure of three safety injection system relief valves to open within the allowable range on November 2. 1996, b. Observations and Findinas On November 2.1996, the safety injection system experienced a slow system pressure transient due to leaking check valves. The system pressure exceeded the relief valve lift setpoint and the relief valves did not lift within the acceptable tolerance. This issue was discussed in inspection reports IR 96-14 and again in IR 97-06. Following the November 2. 1996 event. one of the relief valves was replaced. On September 2.1997, during surveillance testing, the safety injection system experienced another over pressure transient. During the slow transient, the safety injection relief valves failed to open within the acce) table tolerance, including the relief valve that was replaced after the govember 2, 1996 event.
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During the Unit 2, cycle 8 outage, the licensee removed the three relief
, valves to perform an evaluation in order.to determire the root cause for- i the failures. The_ review was documented in PER No. SO972492PER which was com)leted on November 21, 1997. The PER noted that "the subject-valves lad not been recently refurbished, thus allowin to occur which eventually resulted in-setpoint drift.'g slow degradation The PER documented that industry reports had noted that 70% of all relief valve failures were caused by aging,-
The PER noted that "there was no program in place to require periodic refurbishment and since the ASME Code-only requires Class 2 and 3 valves to be tested once in a 10-year period, there is not a significant driving force to rebuild valves due to test failures." The PER-
- concluded that the licensee "does not have a maintenance-program in place to periodically refurbish the Class 2 and 3 Section XI relief:
valves."
c. Conclusions A weakness was identified for not having a maintenance program in-place to periodically refurbish Class 2 and 3 Section XI relief valves. The licensee is in the process of determining how to address this issue,
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M1;4 Personnel Performance Issues Related to an Auxiliary Buildina Isolation-(ABI) Actuation a. Insoection Scoce (62707)
The inspector reviewed the licensee's event critique report related to the inadvertent ABI actuation on September 17-, 1997.
b. Observations and Findinas The ABI actuation event was discussed in -inspection report IR 97-12.
While performing a modification in the radiation monitor _ panel, an instrument technician inadvertently grounded an energized lead. which resulted in multiple control room alarms. loss of approximately 20 control board radiation monitors and loss of approximately 10 control-board radiation monitoring recorders.
The licensee subsequently investigated the event and documented.the review in an event critique report for PER No. S0972109PER. The report noted several personnel errors that contributed to the event. -The report documented a " failure to do an adequate impact evaluation as
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required by SSP-7.53, failure to complete prerequisites before start of .
work and not complying with the requirements of SSP-6.25 to re-plan work if a clearance is not established, and failure to establish a clearance on control circuits when modifications are t1ed into permanent plant equipment as recuired by SSP-12.3. SSP-6.22 and SSP-9.3." In addition the review notec poor work practices in regard to checking for voltage on electrical leads and protecting disconnected leads / wires.
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The inspector concluded that the licensee failed to maet various l procedural requirements for work control and clearance control during implementation of a plant modification. However, the licensee's review of this issue oppeared to be comprehensive. The licensee noted various l corrective actions to address the personnel errors including personnel 1 actions, reinforcing expectations and addressing workmanship issues.
This non-repetitive, licensee-identified and corrected violation is being treated as a non-cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-327, 328/97-17-02).
c. Conclusions An NCV was identified for failure to meet procedural requirements for work control and clearance control that led to an ABI actuation and loss of a significant number of plant radiation monitors (20) and recorders (10).
M1.5 Inservice Insoection a. Insoection Scone (73753)
The inspection consisted of a review of program documents, procedures, an? 3 elected records, Observations were compared with applicable procedures, the Final Safety Analysis Report (FSAR) and ASME B&PV Code Sections V and XI, 1989 Edition. No Addenda (89NA) and ASME B&PV Code Section XI Subsection IWE 1992 Edition 1992 Addenda (92A92).
Specific areas examined included: magnetic particle (MT) examination records: liquid penetrant (PT) examinatier. records: ultrasonic (UT)
examination records: records of eddy current (ET) examinations of reactor vessel thimble tube guides: records of ET examinations of steam generator (S/G) tubing: records of direct visual (VT) examination of supports: records of remote VT examination of the internal area of the reactor vessel: and review of the Repair and Replacement Program.
The inspectors reviewed Inservice Inspection (ISI) program documents and procedures for both proper approval and technical adequacy.
Program documents and procedures reviewed included:
. 0-SI-DXI-000-114.2. "ASME SECTION XI ISI/NDE PROGRAM UNIT 1 and UNIT 2", Revision 2. dated March 20, 1997:
- SEQUOYAH NUCLEAR PLANT UNIT 2 CYCLE 8 INSERVICE INSPECTION SCAN PLAN". Revision 1:
- SEQUOYAH NUCLEAR PLANT UNIT 2 CYCLE 8 AUGMENTED NDE SCAN PLAN".
Revision 1;
- SSP-6.10. "ASME SECTION , AUGMENTED NONDESTRUCTIVE
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EXAMINATION PROGRAM". Revt dated February 3, 1997:
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e N-MT-6. " MAGNETIC PARTICLE EXAMINATION OF ASME AND ANSI CODE COMPONENTS AND WELDS Revision 14. dated August 15, 1997:
- N-PT-9. " LIQUID PENETPANT EXAMINATION OF ASME AND ANSI CODE COMPONENTS AND WELDS. Revision 14, dated Au9est 15, 1997:
- N-UT-18. " MANUAL ULTRASONIC EXAMINATION OF PIPING WELDS AND
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VESSELS WITH WALL THICKNESS 2 INCHES AND LESS". Revision 22 August 15, 1997:
- N UT-19. " ULTRASONIC EXAMINATION 0F WELDS IN VESSELS TWO INCHES AND GREATER IN WALL THICKNESS" Revision 9. dated February 20.
1996:
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.N-UT-21. " ULTRASONIC EXAMINATION OF RCP FLYWHEELS". Revision 5.
dated August 15. 1997:
. N-UT-33. " MANUAL ULTRASONIC EXAMINATION OF STATIC AND CENTRIFUGALLY CAST STAINLESS STEEL PIPING WELDS". Revision 8.
dated August 15, 1997:
- N-UT-37. ULTRASONIC EXAMINATION OF BOLTS AND STUDS GREATER THAN 2" DIAMETER AND RPV FLANGE LIGAMENTS" Revision 6. dated August 15.
1997:
N-UT-39. " MANUAL ULTRASONIC SIZING CF PLANER FLAWS" Revision 3.
dated February 20. 1996:. ,
e N-UT-55 " ULTRASONIC EXAMINATION OF N0ZZLE INNER' RADIUS LECTIONS UTILIZING REFRACTED L-WAVES FROM THE BEND RADIUS". Revision 6.
dated February 20, 1996:
. N-UT-60 " ULTRASONIC EXAMINATION OF SOCKET WELDS TO DETECT CRACKS INITIATING AT THE PIPE I.D. BENEATH THE SOCKET WELD HEAL TO T0E AREA". Revision l'. dated August 15. 1997;
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N-VT-1. "PRESERVICE AND INSERVICE VISUAL EXAMINATION PROCEDURE".
Revision 26. August 15. 1997:
- N-VT-8. " VISUAL EXAMINATION OF PWR REACTOR VESSEL INTERIORS AND CORE SUPPORT STRUCTURES". Revision 7. dated August 15, 1997:
. SSi'-6.9 " REPAIR / REPLACEMENT OF ASME SECTION XI COMPONENTS".
Revision 10- dated September 24, 1997.
The inspectors reviewed selected records of ISI examinations. These records includct MT PT. UT. ET and VT examination reports: video tape of the remote VT internal examination of the reactor vessel: and computer data of-ET examinations of steam generator tubes. In addition the inspectors examined records for the nondestructive ex' aination (NDE)
personnel and ecuipment utilized to perform ISI examinations. The records includec : NDE equipment calibration and consumable materials
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certification; and records attesting to NDE examiner qualification, certification and visual acuity, b. Observations and Findinas Procedure N-PT-9, Revision 14. permits PT examination using Magnaflux cleaner SKC-S. penetrant SKL-S and developer SKD-S in a temperature range of 25 135 F. ASME B&PV Code.Section V Paragraph T-674.3, requires PT procedures to be qualified for examination at temperatures below 60*F and above 125 F. This qualification is to be accomplished by means of a comparison between the sensitivity of the PT procedure including consumables (cleaner, penetrant and developer) at the lowest and highest temperatures to be used and the sensitivity of those same consumables used at a temperature between 60-12C'F. The licensee was l
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unable to provide objective quality evidence that cleaner SKC-S, penetrant SKL-S and developer SKD-S had been qualified outside the range of 60-125*F. The inspectors did not identify any examples where the licensee had used cleaner SKC-S aenetrant SKL-S or developer SKD-S outside the range of 60-125 F. T1e licensee planned to issue a Problem Evaluation Report to address this issue. The licensee's inability to produce records sunorting NDE weakness in their OE prograo procedure qualification, was considered a
. The review of consumables rIso identified that the qualification documentation for the Shervin family of penetrant materials for the tem)erature range of 25-135 F erroneously identified the penetrant used as )R-40 vice DP-40. By contact with Sherwin, the licensee determined that Sherwin never manufactured penetrant type DR-40, therefore the DR-40 referenced in the qualification report was a typographical error.
The licensee planned to correct the documentation and notify all holders of controlled copies of the NDE manual of the same.
The inspectors found that, during the licensee's pre-examination review of contractor NDE examiner qualification and certification documentation, the licensee failed to identify discreaancies.
Certificates of visual acuity for the NDE personnel w1o performed ISI examinations included a number of deficiencies including: missing qualification / training of the visual acuity test administrator; missing signature of visual acuity test administrator and indeterminate statement of results. During the ins)ection, the licensee acquired corrected visual acuity certificates )y means of FAX transfer. This lack of licensee attention to detail. in not identifying the certificate discrepancies during a review, was considered a weakness in the licensee's NDE program.
The ASME B&PV Code requires calibration standards to be metallurgict".y similar to that of the material to be examined. Certified material test reports (CMTR)s are usually used to demonstrate the metallurgical similarity. The inspectors found that the document trail, to substantiate metallurgical similarity from the examination reports to the CMTRs was not clearly linked in most cases. For two calibration standards, there was no document of similarity (50-57 and S0-102). The
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11-licensee indicated that both the heat number and the calibration-standard identification number should be stamped on each standard. This.
if verified. would provide the missing link from the-examination-reports to the CMTRs. Due to time constraints and the physical _ size of S0 57 l
and 50102, verification of proper heat and identification number marking on those standards was=not possible during this irispection. The-licensee indicated that they intended to verify proper traceability of
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S0-57 and S0-102.-as well as all other UT calibration standards used
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linkage of traceability for UT calibration standards was considered a ,
y negative finding in the licensee's.NDE program.
L Except as noted above. records demonstrate that ISI examinations were L
' conducted in accordance with approved procedures by qualified and certified examiners using certified / calibrated equipment and materials.
The licensee, by letter dated February 10. la7. requested NRC relief-from the repair and replacement aspects of the Containment Inspection Rule for a period of one year. By letter dated April 28, 1997 the Office of Nuclear Reactor Regulation (NRR) granted the relief to September 9, 1997. The licensee had implemented the Containment Inspection Rule re) air and replacement (R/R) program by issuance of:
SSP-6.9. " REPAIR / REPLACEMENT OF ASME SECTION XI COMPONENTS". Revision-10. dated Se or_ Class CC ptember-24. 1997.The licensee-indicated that no Class MC repairs or re)lacements were made during the period September 10-23, 1997. T1e inspectors noted that Procedure-SSP-6.9.
addressed ASME B & PV Code Subsection IWE (Class MC), but not Subsection IWL (Class CC) concrete components. The licensee indicated that the repair and replacement of Class CC components would be handled on a case by case basis.
c. Conclusion Inservice inspection activities observed / reviewed were conducted in accordance with procedures. licensee c 11mitments and regulatory requirements. Weaknesses in the licumee's NDE program were noted relating to the licensee's-inability to produce records supporting NDE procedure qualification; and the licensee's inadeguate review of visual acuity certificates. Unclear linkage of traceability for UT calibration standards was a negative finding in the program. The licensee had-implemented the Containment Inspection Rule in a satisfactory manner M1.6 failure of Valve 2-FCV-6-166A a. Insoection Scooe (62700)
At 9:20 p.m. November 12. 1997, during water hammer induced movement, the lower-flow control valve (FCV) from 2C4 to 2C5 feedwater heater, valve No. 2-FCV-6-166A. parted with a brittle fracture in the downstream neck section between the outlet flange and the main section of the body.
The FCV was not in service at the time of the failure, having previously been isolated, both up and down stream, for stroking. To evaluate the
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12 licensee's actions associated with the failure of FCV 2-FCV-6-166A. the inspectors reviewed selected records, interviewed licensee personnel, conducted a walkdown inspection of th? failure location and examined the failed valve and a similar valve that failed in 1995.
The following documents were reviewed:
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Masoneilan manual for 10000 series control valves:
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FSAR Section 10.4.9.2:
. SON-DC-V-3.0, " CLASSIFICATION OF PIPING, PuliPS. VALVES AND VESSELS", Revision 12 dated July 15, 1995:
. ANSI B31.1, 1967:
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TVA SPECIFICATION 1477 FOR HEATER DRAINS AND LEVEL CONTROLLERS FOR SEQUOYAH NUCLEAR PLANT UNITS 1 AND 2 AND WATTS BAR NUCLEAR PLANT UNITS 1 AND 2":
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ANSI B16.1-1975, " Cast Irca Pipe Flanges and Flanged Fittings":
- Drawing CCD N0: 1,m 47W805-4 R13, " FLOW DIAGRAM H.P. - HEATER DRAINS & VENTS";
. Drawing CCD NO: 1-47W805-2 R19. " FLOW DIAGRAM LOW PRESSURE HEATER DRAINS & VENTS" Observations were compared with the licensee's program, 10 CFR 50.65 (the Maintenance Rule), and the FSAR.
b. Qbyervations and Findinas A similar event had occurred April 4, 1995 to 2-FCV-6-147A. The FCV.
associated with the 2B4 and 2B5 feedwater heaters, was documented in PER No. SO950259PER. In the 1995 event, the FCV was isolated upstream only, due to a leaking bellows downstream of the FCV. In the 1995 event. FCY 2-FCV-6-147A parted with a brittle fracture in the upstream neck section {
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between the inlet flange and the main section of the valve body. The licensee's failure analysis report attributed the 1995 FCV failure to the water hammer loads on a grey cast iron valve which was " considered the weak point in the piping segment, hence failure at this point would be ex)ected under the exposed conditions." The 1995 water hammer was attri)uted to a 1.75" low spot in an otherwise horizontal 6-inch pipe.
The licensee had inspected the lines on the 2A4 and 2C4 heaters and found no low spots. The low spot had been considered to be the result of improper alignment during welding of the pipe segment. The licensee considered the preceding "to be an isolated and unique cause" The licensee indicated that in view of the 1997 FCV failure, that the low spot theory was a contributing cause but was not the root case of the water hammer leading to the 1995 FCV failure. During the inspection
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period November 17-21, 1997, the licensee was conducting a root cause analysis for the failure of 2-FCV-6-166A, to be documented in PER S0972573PER. The corrective action plan was expected to be in place by the middle of December 1997.
The Masone11an manual describes the FCV as a double ported top and bottom guided control valve with a type 37 spring diaphragm actuator.
The failed valve bodies were identified as gray cast iron specified as ASTM A-126 Class B with a minimum tensile strength of 31 ksi, no yield strength or elongation specified. The inspectors determined, based on the licenste's design criteria. that gray cast iron Class B of ASTM A-126 was an appro?riate material for the FCVs discussed in the above section. When t1e licensee attempted to procure a replacement FCV, they were informed that Masone11an gray cast iron valve Class B of ASTM A-126 was no longer availdble. Valve 2-FCV-6-166A was replaced with a vaha of carbon steel ASTM A216 Gr WC9. ASTM A216 Gr WCB specifies :
tensile strength 70 to 90 ksi, yield strength 36 ksi, elongation 22% and 35% reduction in area. The inspectors further determined that carbon steel ASTM A216 Gr WCB was an appropriate material for the FCVs discussed in the above section. The licensee was actively pursuing this problem and planned to have a corrective action plan to be in place by the middle of December 1997. NRC followup of this corrective action effort is identified as Inspector Followup Item. IFI 50-328/97-17-03.
Water Hammer Failure of Heater Drain Flow Control Valve.
c. Conclusion-The licensee's actions, reviewed by the inspectors, to address the failure of FCV 2-FCV-6-166A. were appropriate and consistent with 10CFR 50.65.
M1.7 On-Li u Maintenance a. Insoecti,on Scooe (62706 and 62707)
The inspectors reviewed selected licensee administrative procedures for implementation of 10 CFR 50.65 (Maintenance Rule) requirements. The inspection specifically focused on paragraph (a)(3) of the Rule which stated that the total impact on plant safety should be taken into account before taking equipment out of service for monitoring or preventative maintenance. The inspector's focus was on those structures, systems and components (SSCs) that were within the scope of the Rule, that had safety or risk significance, and that had preventative or corrective maintenance performed during the period.
b. Observations and Findinas During this period, the inspectors reviewed the licensee's processes for evaluation of the total impact on plant safety when taking equipment out of service for mainterance. The licensee implemented the requirements for the Maintenance Rule by Tennessee Valley Authority Nuclear (TVAN)
Standard Prcy ns and Processes (SPP)-6.6. "MAINTENANCt' RULE PERFORMANCE t
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INDICATOR MONITORING. TRENDING AND REPORTING - 10CFR50.65." Revision 0 dated June 20, 1997. This SPP implemented the Maintenance Rule requirements at all three TVAN plants. During the review, the inspectors noted the licensee had not clarified the definition of maintenance to include operational errors associated with a maintenance activity as discussed in Regulatory Guide 1.160. " MONITORING THE EFFECTIVENESS OF MAINTENANCE AT NOCLEAR POWER PLANTS." Revision 2. dated March 1997. The inspectors discussed this issue with the licensee and they stated they considered the manner in which their arogram addressed the definition of maintenance was in accordance with t1e NRC staff's
position which was discussed in the Winter of 1997. The inspectors discussed the licensee's comments with NRC headquarters staff and again communicated the discrepancy in SPP-6.6 to licensee personnel. The inspectors noted the licensee's processes to address operational errors associated with maintenance activities was in accordance with their corrective action program: however their definition of maintenance did not inciude functional failures associated with return to service errors *
after performance of a maintenance activity. No examples of inappropriate review and evaluation of maintenance preventable functional failures were identified during this inspection. The licensee requested that further discussions be held with the headquarters program office to resolve this issue. The inspectors were unable to resolve this administrative issue prior to the end of the inspection period. This issue was identified as one example of an inspector followup item (IFI 50-327, 328/97-17-05). Followup of Maintenance Rule related activities.
The licensee implemented the requirements of paragraph a(3) of the Rule per Site Standard Practice (SSP)-7.1. " WORK CONTROL." Revision 16.
SSP-7.1 provided a " EQUIPMENT TO PLANT RISK MATRIX." Attachment 4 which was u3ed by work schedulers and others in assessing risk in accordance with the plant's Probablistic Safety Assessment (PSA). The inspectors noted the matrix essentially listed single components and evaluated their risk level. The matrix also provided notes which addressed the extent of combinations of equipment and stated "a PSA knowledgeable risk engineer or the ... Sentinel program should be consulted prior to scheduling the removal of multiple risk significant systems, not included in the matrix, ...from service." The inspectors discussed the Sentinel computer prograin with licensee engineering and operations personnel and determined this risk evaluation process was in the implementation stages. Clarification notes in the matrix and Sentinel were judged to be an improvement in processes for effective use of PSA information to evaluate plant risk. The inspectors monitored selected acti"ities ut licensee daily meetings including the 7:30 a.m.
maintenance meeting, the daily team meeting, the scheduling review of new work requests meeting, and the dail" schedule meeting. The licensee relied on the schedule and working to tfie schedule as the primary meat.
of risk defense for taking equipment out of service for corrective or preventative maintenance. In addition, the schedule normally allowed only one high risk component out of service at a time, with special management focus on these activities. The inspectors judged the
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licensee's implementation of maintenare: processes in this area as adequate.
The inspectors conducted several plant tours to assess hcusekeeping and general plant material condition. Areas toured included the auxiliary i building, control building, turbine building, emergency raw cooling water pump-house, and emergency diesel generator (EDG) building. Plant material condition and housekeeaing were judged to bc good. However, for several components (EDGs. clarging pumps, booster pumps, and heater drain pumps), oil leakage was observed.
Two systems were reviewed with appropriate engineering personnel. The reactar protection system (RPS) was reviewed and the inspectors noted the licensee monitored the two major systems which make up the RPS, the reactor trip system and the engineered safety f3atures actuation system, at the train level. Further NRC review of the adequacy of this level of RPS monitoring is a second example of IFI 50 327.328/97-17-05, Followup of Maintenancs Rule related activities. The radiation monitoring system was reviewed and the inspectors noted that several plant modifications had been made to improve performance of this system. In addition, other corrective actions were in process to address other failures. The inspectors noted improvement in the performance of the radiation monitoring system based on the licensee's implementation of corrective actions for this 10 CFR 50.65(a)(1) system. However, radiation monitoring problems continued to require implementation of compensatory measures during the inspection period. T M inspectors judged these systems were being appropriately monitoreo and corrective actions implemented based on identified problems.
The inspectors reviewed selected work requests which were identified by tags in the plant. Older requests were selected. In the cases reviewed, the licensee was taking appropriate actions to address the issues. Based on the review, the inspectors judged appropriate focus was being placed on reducing backlog for old work items, c. C.gaclusions The licensee's processes for taking into account the total impact on plant safety before taking equipment out of service for monitoring or preventative maintenance was adequate. Observed plant housekeeping and material condition was good. Improvements were noted in the performance of radiation monitoring system components.
An Inspector Followup Item was identified for followup of Maintenance Rule related activities.
M1.8 Emeroenc'/ Diesel Generator (EDG) Surveillance Observation a. Insoection Scooe (61726)
The inspector observed ongoing EDG surveillance testing conducted on December 10. 1997, in accordance with Surveillance Instructions. 1-SI-
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l OPS-082-007.B.' Diesel Generator IB-B Operability Test, and SI-102 M/M.
[ Diesel Generator Mechanical Inspection._
- - b.. Observations and Findinos i' The inspectors noted that the surveillance activities were adequately
, performed. During operation of the 18-B EDG an infrared thermometer was
- available to verify engine exhaust temperatures due to erratic
- . indication of some thermocouples. No problems were identified during -
' observation of the ongoing surveillance testing.
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M2: Maintenance and Material Condition of Facilities and Equipment
- M2.1 .EDG Reliability Imorovement Proaram a. Insoection Scoce (62700)-
- - The inspector reviewed the licensee's program for improving EDG j reliability. -As the result of recent failures the licensee had made numerous contacts with the EDG vendor. Engine Systems Inc.. and
evaluated the 3erformance history of the LDGs in order to identify any
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improvements tlat could improve reliability or reduce unavailability of the EDGs.
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b .~ Observations and Cindinas
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The inspector held discussions with members of licensee management and reviewed the EDG system health report along with other documentation-provided by the licensee. During this review the inspector noted that
unavailability of EDGs at Sequoyah had met licensee's established goals
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for the last 24 months. Additionally, the inspector noted that reliability.of the EDGs had not exceeded established trigger values.
4 Although there had been several failures, the EDGs had not been classified as-(a)(1) under the licensee's Maintenance Rule Program. in that the licensee's performance criteria were not exceeded. The inspector noted that these failures had r.ot.resulted from any common causes.
.The inspector noted that the licensee had identified numerous
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improvements intended to improve reliability and reduce unavailability
--of the EDGs. These included =. design changes to replace the priming fuel oil canister filters and turbocharger lube oil cartridge ~ filters with newer spin-on type filters to reduce possibility of leaks: replacement of-cylinder exhaust thermocou indetected injector problems:ples to reduce the possibility ofreplacement of 1 were nearing end of life: replacement of obsolete field flash relays:
modification of generator and electrical board fan to operate only when the engines are running: correction of fuel oil transfer pump control switch setpoint to provide additional conservatism from minimum TS-requirement of 250 gallons in the day tank; implement vendor-recommendation-to improve reliability by removal of Z3 zenor diode from
'SA-1 differential relays for the emergency feeder breaker to the
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shutdown boards: and change engine immersion heater control circuit to interrupt 480 VAC power when the engine was operating to increase expected life of heater elements. Additionally, the licensee plans to develop a critical spare part list for EDGs and implement corrective action recommendations from Engine Systems. Inc. to address potential cylinder head cracking due to injector bore stress concentration. The inspector noted that TDCNs had been issued to implement several of the above planned changes. The inspector determined that numerous corrective actions were identified during the licensee's evaluation which if implemented should result in improvement in overall reliability of the EDGs.
c. Conclusions
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The inspector determined that the documented values for reliability and unavailability of EDGs at Sequoyah had met licensee's established goals for the last 24 months. Additionally, the inspector determined that numerous corrective actions had been identified during the licensee's evaluation of EDG reliability.
M2.2 EDG Performance Trendina l a. Insoection Scone (62700)
The inspector held discussions with the EDG system engineer and reviewed-available performance data for the EDGs. Sequoyah has four EDGs each of which includes a pair of tandem mounted 16 cylinder two stroke diesel engines connected to a common generator, b. Observations and Findinos The inspector reviewed available performance data for engine cylinder exhaust and turbocharger inlet temperatures. During the review of performance data of EDGs the inspector noted that very little trending of available data had been performed for c'esel engine cylinder exhaust temperatures and turbocharger inlet temperaues. The permanently installed instrumentation provides input signals for control roora alarms and valuable information for evaluating performance of the EDGs.
Cylinder exhaust temperatures provide the only available met od for measuring actual loading conditions for individual cylinders and would be needed for evaluating a potentially stuck or fouled fuel injector.
rbocharger inlet temperatures provide valuable information for deurmining adequacy of balancing between the two tandem engines driving a common electrical generator. Old thermocouple data prior to 1997 was not readily available and the licensee's current program for trending available data was poor. This may have been due, in part, to poor material condition of the engine thermocouples. Several of the thermocouples were failed or provided intermittent indication, resulting in the lack of confidence in the readings. During tours in the EDG rooms the inspector noted that some of the conduit supports for the thermoccuples had failed and portions of the conduits were supported by the associated thermocouple wiring. This issue is further discussed in
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Section M2.z. In addition to thermocouple readings. Various other EDG system operating parameters were recor'ied by the licensee during scheduled EDG testing. These included ERCW tem]erature lube oil temperature and pressure, fuel pressure, and vi) ration data on EDG bearings and supporting equipment. The licensee was not able to provide the inspector with any trending data on any of these parameters. The licensee's performance trending of the EDGs was considered a weakness.
During the review of completed surveillance packages for 2-SI-0PS-082-007.B. Diesel Generator 28-B Operability Test, and SI-102 M/M. Diesel Generator Mechanical Inspection, the inspector nuted an apparent loading imbalance between the two diesel engines driving the common generator.
These packages were associated with testing of EDG 2B which had been performed on November 26, 1997. Thermocouple readings recorded in SI-102 M/M at 100% load indicated a 230 degree difference in turbocharger inlet temperatures betwecn the 281 and 2B2 engines. This exceeded the limit of 200 degrees established by the licensee. The inspector was informed that the licensee had considered as invalid the indicated difference of 230 degrees due to a known faulty turbocharger inlet thermocouple on one of the two engines on EDG 28-B. However, the inspector also noted that the 16 cylinder exhaust thermocouple readings for both engines indicated an average cylinder temperature for engine 2B2 that was 87 degrees higher than for engine 2B1. Since average cylinder temperatures can not be directly compared to turbocharger inlet temperature without previous engine test data at known loading conditions, the actual amount of loading imbalance was not known. The inspector discussed with licensee management the concern that this condition indicated a load imbalance which was not specifically addressed by the licensee's arocedures. Additionally, no specific criteria for shutdown of an EDG with a load imbalance between engines was identified by the inspector during raview of the vendor tech manual.
SON-VTM-P318-0010. The system engineer produced a vendor manual change request which contained recommended guidance for securing the engines due to excessive temperature on the hotest engine cylinder. This change request was pending final review by licensee management and had al eady received vendor concurrence. The above operating conditions had been within the proposed criteria. Additionally. the inspector noted that the licensee had issued a work order for balancing of the engines during an upcoming EDG outage. The inspector concluded that although operating parameters for the 2B-B EDG had inoicated a load imbalance between the two tandem engines, a condition had not existed which would have required that EDG 28-B to have been considered inoperable.
During observation of surveillance testing of the IB-B EDG the inspector noted that thermocouple data was taken by operations and maintenance personnel. The inspector noted that the thermocouple readings obtained during engine operation were consistent with EDG loading conditions and there was evidence of loading imbalance between the two engines on the 1B-B LM.
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c.- Conclusions The licensee's trending program for the EDGs did not provide sufficient historica1'information to support identification of degraded engine-performance.
M2.3 Material Condition Walkdowns a. Insoection Scone (62700)
The inspector toured each of the four EDG rooms to evaluate.the material. .
-condition of equipment located in those areas, b. Observations and Findinas <
During observation of surveillance testing of EDG 1B-B the inspector'
noted several minor fuel and/or lube oil leaks. Most of the leakage was associated with the 1B2 diesel engine. The-inspector also noted several other minor leaks on each of the remaining diesel engines. One lube oil leak on the 1A1 diesel engine on EDG 1A required partial engine disassembly to: repair. The licensee informed the inspector tht this oil leakage had been previously identified by the licensee. Repairs of this leak had-been deferred until the 12-year EDG inspection which is scheduled -for 1999. The inspector did-not identify any significant leakage which would require immediate repairs prior to considering the-EDG operable.
-During tours in.the EDG rooms, the inspector noted that conduit supports for the thermocouples had failed and portions of the conduit were supported by the thermocouple wiring. This condition appeared to have existed for an extended time period. The inspector was informed that the licensee had previously identified.the problem, had arocured new thermocouples, conduits, and associated components and tlat replacement of the thermocouples on all four EDGs was scheduled to occur during planned-EDG outages during-January & February 1998.
c. Conclusions Several oil leaks were noted on the EDGs including one lube oil leak that will require partial engine disassembly to repair. The inspector determined that the-identified leakage would not require immediate repairs.
- M8 Miscellaneous Maintenance Issues-(92902)
M8.1- (C'osed) LER 50-327/97005. Two of Six Tested Main Steam Safety Relief
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Valves Were Not-Within Technical Soecification Setooint Tolerance.
U)on determination-of the condition (one of the valves was found to be t1ree psig below the setpoint tolerance and the other valve was found to
.be two asig above the setpoint) the two valves were considered inopera)le and the TS action statement was entered. The valves were
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' adjusted, retested..found acceptable and the action statement was
. exited. The condition was attribeted to setpoint drift.
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M8.2 (Closed) LER 50-327/97009. Failure to Perform Resoonse Time Testina of
! the Containment Radittion Monitor f a lowina Maintenance Activities as Reauired by Technical Soecifications. Following identification of the conditions, the licensee determined that the radiation monitors would have performea their function as required by TS. This LER was a minor
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issue'and was closed.
M8.3 (Closed)-LER 50-327/97010. Failure to Procerly Return a Portion of the Fire Orotection System to Service Followina Modification Activities.
During the period that the auxiliary control room sprinkler system was inoperable (approximately one day) the fire detectors and hose stations in the aida were operable. Additionally, a fire watch was in the area outside the auxiliary control room for most of the time of inoperability. This LER was a minor issue and was closed.
M8,4 (Closed) LER 50-327/97004. Revision 00. Revision 01. and "' vision 02.
Failure to Procerly Perform Surve'llance Testina on Circuit Breakers.
The inspector concluded that the '1censee identified several examples ,
(23) where the surveillance requirements of TS 4.8.3.1 or 4.8.3.3 were not met. The inspector reviewed the corrective actions as stated in the LERs and concluded that=they were reasonable and complete. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of-the E C Enforcement Policy (NCV 50-327, 328/97-17-04).
M8.5 (Closed)-LER 50-328/97002. Failure to Maintain Two Offsite Power Sour g as Reauired by Technical Soecifications. This event was discussed m Inspection Report 50-327, 328/97-03 and was identified as a Non-Citec Violation (NCV 50-327, 328/97-03-03). No new issues were revealed by the LER.
M8.6 (Closed) LER 50-328/97S01. Vandalism of Electrical Cables. This event was discussed in Inspection Report 50-327, 328/97-16. No new issues-were revealed by the LER.
M8.7 (Closed) URI 50-327. 328/97-12-02. Potential Inadeauate Imoact-Evaluation. The inspector reviewed the completed PER No, SQ972109PER,
.which addressed this event. The inspector's-review is documented in-Section M1.4 of this report. NCV 50-327. 328/97-17-02 was identified during the review. Based on this review, including the identified NCV, this item is closed.
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M8,8 1 Closed) IFI 50-328/97-12-03. Follow Resolution of Safety Iniection Check Valve Back-leakaae and Relief Valve Setooint Orift.
- (Closed) VIO 50-328/97 06-08. Inadeauate Corrective Actions for L Deficient Safety Iniection System Relief Valve liftina Set ooints.
i The inspector reviewed the root cause evaluation documented for the ~
- - relief valve setpoint drift and documented that review in Section M1.3 I .of this -report. The licensee determined that the relief valve Set
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' points had drifted due to aging and that the licensee did not have a '
maintenance program in place to periodically refurbish AShE Class 2 and 3 Section XI relief valves. The licensee determined why the relief
. valves were drifting and was in the process of developing either a
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preventive maintenance program or to reduce the interval for relief valve testing. Section M1.3 of this report identified a program
, weakness for not having a preventive maintenance 3rogram for
. refurbishing ASME Class 2 and 3 relief valves. T1e inspector noted that work requests were written to repair the leaking check valves. Based on f, this review IFI 50-328/97-12-03 is closed.
4' In addition. the inspector reviewed the corrective actions for VIO 50-
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328/97-06-08. After the relief valvas failed to open on November 2.
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1996.- the licensee performed an engineering structural analysis which provided acceptable documentation-for the as-found condition of the relief valves. This evaluation provided documentation for. continued oaeration of the plant. During the Unit 2. cycle 8. refueling _ outage tle licensee replaced all three safety injection relief valves. BNed on this review.-including the root cause analysis' documented % e, VIO 50-328/97-06-08 is closed.
M8.9 (Closed) IFI 50-327. 328/97-01-03. Review the Process of Usino installation Dates Versus Calibration Dates to Meet Surveillance Start Dates. Inspection report IR 97-01 documented a problem with using the installation date-versus the calibration date to start the active
- surveillance date for a Unit-2 reactor trip breaker. Using the f
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installation date versus the actual calibration / surveillance date had C resulted in a violation, which was also documented in IR 97-01', .Since February 1997, the inspectors have performed an ongoing review of
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surveillances to identify any other occurrences of this concern. No additional examples have been identified and based on this review this item is closed.
M8.10 FClosed) VIO 50-327. 328/95-09-06. EDG Air Start Pressure Switch Set
- ncorrectiv. The licensee's letter dated November 12. 1996, stated that
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the problem with the original pressure switches had been due to an excessive tolerance in the reset adjustment mechanism. This condition
.had resulted in repetitive failures attributed to ineffective root cause
, analysis and corrective actions. The pressure switches were re i
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with_new pressure switches of a design to correct the problem. placed l
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The inspector reviewed corrective actions associated with this '
violation. Corrective actions included additional training of technical i support personnel on root caure analysis and corrective actions.
Records to show that the new pressure switches had been re) laced were also reviewed. The inspector concluded that the licensee lad determined the full extent of the violation and developed corrective actions needed to preclude recurrence of similar problems. Corrective actions stated in the licensee's response have been inplemented.
M8.11 (Closed) V10 50 327. 328/96-11-04 Review of EDG Air Start Relief Valves set incorrectly . The licensee's letter dated December 19. 1996, stated that the incorrectly set air start relief valves were due to an incorrectly specified design pressure. The licensee performed a review of plant systems to ensure that relief valve set pressures were consistent with the code of record for associated system design pressur.
The inspector rev ewed portions of TVA Calculation SON DES 1-008 which documented the licensee s evaluation of the EDG air start system and
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determination of proper design pressure. During this evaluation the licensee had determined the new design pressure of 330 psig and identified the reed to replace the existing relief valves with a new soft seat design. The in pector noted that incorrect relief valve
, settings for several other systems were also identified during the
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licensee's evaluation. The inspector verified that these additional deficiencies had been documented in accordance with the licensee's corrective action program. The inspector verified that the licensee had issued Design Change T-12850 A To replace the air start relief valves.
The inspector noted that this design change was scheduled to be
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implemented in April 1998. The inspector concluded that the licensee had determined the full extent of the violation and developed corrective actions necded to preclude recurrence of similar problems. Corrective
, actions stated in the licensee's response with exception of actual relief valve replacement have been implemented.
M8.12 (Closed IFI 50-327. 328/97-06-03. EDG Reliab lity Imorovements.
This issue had been identified to review the licenser's plans for EDG reliability improvements.
The irepector held discussions with various menbers of licensee
- management and reviewed plans for EDG reliabil!ty improvements. The results of that review were previously documented in Section M2.1 of this inspection report. The inspector determined that numerous corrective actions were identified during the licensee's evaluation of EDG reliability which if implemented should result in improvement in
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overall reliability of the onsite standby emergency electrical power supply. Based on that review the inspector em .uded that the licensee -
had adequately addressed the original cons associated with EDG reliability.
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III. EngiDatting E7 Quality Assurance in Operations E7.1 Hisassianment of Fuel Assemblies Durina Unit 2 Core Desian a. 10SDfCtionscooe(37551)
The inspector reviewed the circumstances which resulted in the larger than expected deviations in radial assembly power during Unit 2 power distribution testing following the U2C8 refueling outage.
b. Observations and Findinos On November 6.1997, during Unit 2 startup power distribution testing at 30% power, reactor engineers observed unexplained indications from the flux map. Power escalation was halted while an investigation and rasolution of the problem was pursued. The licensee subsequently discovered that 16 fuel assemblies associated with 2 fresh fuel assembly batches (11E and 11F) were misassigned and were interchanged (all 8 assemblies in batch 11E were interchanged with all eight assemblies in batch 11F) in the core loading alan provided by Framatome Cogema Fuels-(FCF). With the exception of t1e misassignment, the assemblies had been manufactured pro)erly and correctly loaded into the reactor as instructed by FC . T 2 only difference between batches 11E and 11F was the configuration of the 16 gadolinia pins within each assemt'ly.
Reanalysis to generate a new data base for the "as loaded core" was completed by FCF and Unit 2 continued the escalation to 100% power. The
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licensee determined that the changes to the core did not result in any challenges to the core safety cr operating limits.
The licensee determined that FCF identified the root cause of the event to be human error during the creation of the full core loading plan by FCF, The licensee initiated PER No. SQ972547PER to document the event and to track corrective actions assigned to FCF and the licensee.
C. [&n_Gjjjjj Q.n5, The inspectors determined that the licensee promptly identified and followed up the Unit 2 fuel misload event, and ensured that causo was found and corrected.
E8 Miscellaneous Engineering Issues (92903)
E8.1 (Closed) LER 50-327/95001. Rev'sion 1. Gas Accumulation in the Residual Heat Removal (RHR) System Resu'ts in P10e Movement Followina Startino of the RHR Pumos. During the Unit I refueling outage (UlC8)1n April 1997 a modification was implemented to install a new remotely operated high pcint vent on each train (A & B) of the safety injection system header and a manual-vent on train A-header-in the seal table room. Venting of the RHR discharge piping is currently performed monthly using the newly 3 installed vent valves. Before the vent modification, the gas volume was
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14 cubic feet. The latest trending performed in October 1997 indicated the gas volume to be 11 cubic feet. A similar modification had been planned for the Unit 2 October 1997 (U2C7) refueling outage but was
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subsequently deleted from the outage scope due to trending which had not shown gas buildu) in Unit 2 and due to an outage manpower shortage.
Trending of the Jnit 2 gas accumulation had shown the gas volume to be averaging less than 2 cubic feet since June 1996. Unit 2 RHR discharge piping is also currently vented monthly. The modificatior to add vent valves to Unit 2 has been rescheduled for the next Unit 2 a fueling outage, but will be reevaluated by the licensee basd on gas trending and other outage issues.
Revision 1 of this LER provided an evaluation of the accumulation of the gas in the RHR system. No new issues were revealed by Revision 1.
Revision 0 to the LER was closed in Inspection Report 95 12. The gas accumulation issue was also previously addressed in Inspection Reports 95 04, 95 06. 95 12, 96-01, 96 08, 96-09, and 95-14 and in NRC Information Notice 97-40.
E8.2 (Closed) LER 50-328/92003. Revision 1. Reactor Trio as a Result of One
)rotection Channel (RTD _oco) Beina ' n the Trioned Condition When an RTD i
.000 in Another Channel Failed. Como~ etina the Two Dut Of-Four Loalc. !
levision 0 of this LER stated that a root cause failure analysis would be performed on an electrical penetration that had exhibited faulty conductors for determination of the specific failure mechanism. The results of the failure analysis were provided as Revision 1 to the LER. '
Concurrent with the failure analysis, a replacement schedule was developed for canister-type electrical penetrations that exhibit high resistance and do not contain a sufficient quantity of spare conductors.
The . inspector verified that the replacement of penetrations has been initiated and is scheduled to continue through the Unit I cycle 9 refueling outage in September 1998.
E8.3 (Closed) IFI 50-327. 328/96 14-03. Review Corrective Actions Related to the Six level B PERs Initiated by Vertical Slice Audit SO9615 Dated November 20. 1996. The inspector reviewed the corrective actions and closure status for eacl. of the six PERs. Although some of the corrective actions were awaiting final review by the site quality assurance organization, the inspector concluded that the licensee's action plan was reasonable and appeared to adequately address each of the six PERs.
E8.4 (Closed) VIO 50-327/97-03-06. Failure of Technical Sucoort to Adeouately Bnglve the Deficient Conditions Related to the TDAFW Condensate Sumo.
The inspector verified the corrective actions described in the licensee's response letter, dated June 11. 1997, to be reasonable and complete. No similar problems wer e identified.
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E8.5 (Closed) VIO 50 327/97-03-07. Failure to Perform a Thorouah Evaluation Prior to Disablina the TDAFW Condensate Sumo H1ah Level Alarm. The inspector verified the corrective actions described in the licensee's response letter, dated June 11, 1997, to be reasonable and complete. No Smilar problems were identified.
E8.6 (Closed) VIO 50-327. 328/95-18-01. Failure to Promotly identify and Correct the Adve se Condition Associated With Dearaded Emeroency Core (po' ina Svstem ECCS) Throttle Valves. The issue involved delay in imp'ementation of interim corrective actions for an identified adverse condition associated with the ECCS throttle valves. The licensee acce)tedtheviolationinalettertotheNRCdatedSeptember4,1996.
In tlat letter the licensee addressed areas where the rianagement Review Committee (MRC) had been coached on the violation and the need to take prompt corrective actions for conditions adverse to quality.
The inspectors reviewed the licensee's response and attended MRC meetings which were held on December 17 and 18, 1997. The inspector noted the MRC demonstrated good safety sensitivity toward conditions adverse to quality and assurance that the scope of review of the issues and apparent causes was broad.
IV. Plant Support R8 Hiscellaneous Radiological Protection and Chemistry Activities (92904)
R8.1 (Closed) LER 50-327/97006. Failure to Perform Surveillance Recuirement Durina Containment Entry. Personnel did not ensure that materials taken into containment during Mode 4 were adequately controlled. The material (oil cloth and Herculite) was fastened to grating and hand railing to 3revent movement, but coulo have potentially become dislodged during a
.0CA event and transported to the two upper containment drains. A radiation work permit, which did not require visual inspections during Mode 4 plant operation, had been inappropriately used to permit installation of the material during Mode 4. The unit was shutting down for a refueling outage and the uninspected material had been in place for approximately three and one half hours with the unit in Mode 4.
Lessons learned were communicated to radiological control personnel and the appropriate procedure was revised to improve administrative controls of containment entries when containment integrity is required (Modes 1 through 4). The ins)ector concluded that the licensee's corrective actions were reasona)le and complete.
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V. Manaoement Meetinas X1 Exit Meeting Summary The inspectors ) resented the inspection results to members of licensee management at tle conclusion of the inspection on December 23. 1997 and on November 21. December 12 and December 19. 1997 (regional based inspections). The licensee acknowledged the findings presented.
During the inspection period, the inspectors asked the licensee whether any materials would be considered proprietary. No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED Licensee
- Bajestani. M.. Site Vice President
- Burton. C.. Engineering and Support Systems Manager
- Butterworth. H., Operations Manager
- Fecht. M., Nuclear Assurance Manager Gates. J., Site Support Manager
- Freeman. E. Maintenance and Modifications Manager
- Herron. J., Plant Manager Kent. C., Radcon/ Chemistry Manager Koehl. D. Assistant Plant Manager O'Brien. B.. Maintenance Manager Salas. P., Manager of Licensing and Industry Affairs
- Summy J., Assistant Plant Manas.r
- Valente J., Engineering & Materials Manager
- Attended exit interview INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62700: Maintenance Implementation IP 62707: Maintenance Observations IP 71707: Plant Operations IP 73753: Inservice Inspection IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92904: Followup - Plant Support
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ITEMS OPENED. CLOSED. AND DISCUSSED Doened lYng item Number Status Descriotion and Reference EA 97 409 01013 Open Failure to Maintain Operable DC Vital Battery Channels.
(Section 08.5)
EA 97-409 01023 Open Failure to follow Procedures While Aligning a Spare Vital Battery.
(Section 08.5)
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EA 97 409 01033 Open Failure to Include Independent Verification Per Procedure While Aligning Vital Batteries.
(Section 08.5)
t NCV 50-327/97-17-01 Open/ Failure to Adequately Review a Hold Closed Order for Accuracy (Section 01.2)
NCV 50-327, 328/97-17-02 Open/ Failure to Meet Procedural Closed Requirements For Work Control and Clearance Control During Implementation of a Plant Modification (Section M1.4)
IFI 50-328/97-17-03 Open Water Hammer Failure of the Heater Drain Flow Control Valve (Section M1.6)
NCV 50-327, 328/97-17-04 Open/ Failure to Follow Surveillance Closed Requirements of TS 4.8.3.1 or TS 4.8.3.3 (Section M8.4)
IFI 50-327, 328/97 17-05 Open Followup on of Maintenance Rule Related issues (Section M1.7).
Closed T._ypg item Number Status Descriotion and Reference URI 50-327. 328/96-09 01 Closed Determine Whether TS 3.3.1.1 Allow One Pressurizer Pressure Channel to be Bypassed at the Same Time that a Second Pressurizer Pressure Channel is Tripped (Section 08.1)
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VIO 50 327, 328/97-01 01 Closed Failure to Maintain Adequate Emergency Diesel Generator Alarm Response Procedures (Section 08.2)
V10 50 327/97 04-03 Closed Failure to follow Procedure for Exceeding Fuel Preconditioning Limitations. Not Logging Changes in Plant Conditions, and Not Informing the Shift Manager of Changes in Plant Conditions (Section 08.3)
URI 50 327/97-04-04 Closed Further Review of Potential Regulatory issues Noted in the Unit 1 Operational Logs (Section 08.4)
LER 50 327/97005 Closed Two of Six lested Main Steam Safety Relief Valves Were Not Within Technical Specification Setpoint Tolerance (Section M8.1)
LER 50 327/97009 Closed Failure to Perform Response Time Testing of the Containment Radiation Monitor Following Maintenance Activities as Required by Technical Specifications (Section M8.2) ,
LER 50-327/97010 Closed Failure to Properly Return a Portion of the Fire Protection System to Service following Modification Activities (Section M8.3)
LER 50 327/97004 Revision 0 Closed Failure to Properly Perform Revision 1 Closed Surveillance Testing on Circuit Revision 2 Closed Breakers (Section M8.4)
LER 50 328/97002 Closed Failure to Maintain Two Offsite Power Sources as Required by Technical Specifications (Section M8.5)
LER 50-328/97501 Closed Vandalism of Electrical Cables (Section M8.6)
URI 50-327. 328/97-12-02 Closed Potential Inadequate Impact Evaluation (M8.7)
IFI 50 328/97-12-03 Closed Follow Resolution of Safety Injection Check Valve Back leakage and Relief Valve Setpoint Drift-(M8,8)
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29 i VIO 50 328/97-06 08 Closed inadequate Corrective Actions for !
Deficient Safety inje' tion System Relief Valve Lifting Set points (M8.8)
IFI 50 327, 328/97 01 03 Closed Review the Process of Using Installation Dates Versus Calibration Dates to Meet Surveillance Start Dates (M8.9)
VIO -50-327, 328/96-09 06 Closed EDG Air Start Pressure Switch (Section M8.10).
V10- 50-327, 328/96-11-04 Closed EDG Air Start Relief Valves Set incorrectly (Section M8,11).
IFI 50-327 .328/97-06-03 Closed Review of EDG Reliability (Section M8.12).
LER 50-327/95001 Closed Gas Accumulation in the Residual Revision 1 Heat Removal (RHR) System Results in Pipe Movement Following Starting of the RHR Pumps (Section E8.1)
LER 50-328/92008 Closed Reactor Trip as a Result of One Revision 1 Protection Channel (RTD Loop) Being ir. the Tripped Condition When an RTD Loop in Another Channel Failed, Completing the Two 0ut 0f-Four Logic (Section E8.2)
IFI 50-327,328/96-14-03 Closed Review Corrective Actions Related to the Six Level B PERs Initiated by Vertical Slice Audit 509615 Dated November 20, 1996 (Section E8.3)
VIO 50-327/97-03-06 Closed Failure of Technical Su)
Adecuately Resolve the )eficient port to Concitions Related to the TDAFW Condensate Sump (Section E8,4)
VIO 50-327/97-03-07 Closed Failure to Perform a Thorough Evaluation Prior to Disabling the TDAFW Condensate Sum Alarm (Section E8.5)p High Level VIO 50-327, 328/95 18 01 Closed Failure to Promptly Identify and Correct the Adverse Condition Associated with Degraded ECCS Throttle Valves (Section E8.6).
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30 LER 50-327/97006 Closed Failure to Perform Surveillance Requirement During Containment Entry (Section R8.1)
eel 50-327.328/97-13 01 Closed Failure to Follow Procedure in Not Closing the #5 Vital Battery Breaker. (Section 08.5)
eel 50-327.328/97-13 02 Closed Failure to Perform Independent Verification and Fa11ure to Properly Conduct AVO Rounds. (Section 08.5)
eel 50-327.328/97-13-03 Closed Failure to Meet the TS LCO Action Requirements of TS 3.8.2.3.B for Vital Batteries. (Section 08.5)
EEI 50 327.328/97-13-04 Closed Failure to Promptly identify an i
l Adverse Condition with the #5 Vital Battery. (Section 08.5)