IR 05000269/1998002
| ML15118A341 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/20/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A339 | List: |
| References | |
| 50-269-98-02, 50-269-98-2, 50-270-98-02, 50-270-98-2, 50-287-98-02, 50-287-98-2, NUDOCS 9804270356 | |
| Download: ML15118A341 (41) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287, 72-04 License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503 Report No:
50-269/98-02, 50-270/98-02, 50-287/98-02 Licensee:
Duke Energy Corporation Facility:
Oconee Nuclear Station, Units 1, 2, and 3 Location:
7812B Rochester Highway Seneca. SC 29672 Dates:
February 8 - March 21, 1998 Inspectors: Scott, Senior Resident Inspector S. Freeman, Resident Inspector D. Billings. Resident Inspector M. Franovich. Resident Inspector, McGuire N. Economos, Regional Inspector (Sections M1.3-M1.6, M2.3)
D. Forbes, Regional Inspector (Sections R1.1-R5)
H. Whitener, Regional Inspector (Section E8.2-E8.4)
Approved by:
C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects Enclosure 2 9804270356 980420 PDR ADOCK 05000269
EXECUTIVE SUMMARY Oconee Nuclear Station, Units 1, 2, and 3 NRC Inspection Report 50-269/98-02, 50-270/98-02. and 50-287/98-02 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspection, and the results of announced inspections by three regional based inspector Operations
The licensee reported a potential non-conservatism in the procedure for response to Appendix R fires in accordance with the requirements of 10 CFR 50.72. The compensatory actions established appeared to be adequate. (Section 01.3)
The shutdown of Unit 2 and reduced inventory operations were completed properly with deliberate operator action, good supervisory oversight, and good procedure adherence. (Section 01.4)
A non-cited violation was identified with three examples for failure to follow procedure. (Section 04.1)
Failure to complete an adequate review of all items necessary for Unit 1 startup resulted in a non-cited violation. (Section 04.2)
Maintenance
A violation was identified for failure to follow the nuclear site directive for modifications when repairing the Unit 2 turbine driven emergency feedwater pump hotwell suction line. (Section M1.2)
The licensee's response to the Unit 1 pressurizer surge line drain line vibration phenomenon was appropriate. Maintenance and engineering provided good coverage of the issue. Evaluation of the problem and corrective actions taken and planned were consistent with plant safety and code requirements. (Section M1.3)
The Unit 2 low pressure injection cooler test was performed in a well planned manner, the applicable procedure was followed, personnel were well qualified to perform their assigned tasks, and the results showed that low pressure injection coolers 2A and 2B are capable of performing their design function. (Section M1.4)
The licensee's response to the apparent snubber lockup problem on the 1B2 reactor coolant pump motor was well planned and carried out in a timely manner. Soliciting assistance from the vendor resulted in the correct diagnosis of the problem and produced positive result (Section M1.5)
Segments of the licensee's third ten-year inservice inspection interval program that were reviewed complied with Code requirements. Inservice inspection examinations observed were performed in a satisfactory
manner. Fabrication and examination records of high pressure injection nozzle component welds were consistent with Code requirements and licensee commitments. Technicians were well trained and had good knowledge of plant equipment and procedural requirements. The licensee's evaluation of inspection results were documented with accuracy and clarity. (Section M1.6)
A violation of procedural requirements was identified for foreign material control practices during maintenance in the Unit 1 and 2 spent fuel poo (Section M2.1)
Material condition in the Unit 1 west penetration room was deficient. A violation was identified for failure to follow a minor modification instruction for adequate packing gland adjustment on valve 1HP-28 (Section M2.2)
An unresolved item was identified for past operability concerns for improperly installed packing gland followers for valve 1HP-14 (Section M2.2)
The licensee's failure to implement procedural requirements for material condition and housekeeping practices on safety-related components and in the areas housing these components and structures was identified as a violation. (Section M2.3)
Corrective actions as a result of an inadvertent start of the'Unit 3 standby component cooling pump heightened the sensitivity of instrument technicians to procedural compliance and proper communications. The inspectors considered this a positive result of the licensee's recovery plan. (Section M4.1)
A non-cited violation was identified for failure to follow procedure when calibrating a component cooling flow transmitter. (Section M4.1)
Engineering
The licensee used an acceptable approach to determine the operability of the high pressure injection system injection and crossover valves after
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the failure of valve 1HP-27 to close. (Section E1.1).
- The past operability and control of preventive maintenance for valve 1HP-27 was left unresolved pending further review. (Section E1.1)
An unresolved item was identified on engineering review of as-built conditions for the reactor building emergency sump and the borated water storage tank level instrumentation. (Section E3.1)
The licensee failed to make a required 1995 10 CFR 50.46 report. This was identified as a non-cited violation. (Section E3.2)
The licensee discovered that design errors had been introduced into reactor physics analysis for power-imbalance on all three Oconee unit This.problem was documented as a design control violation. (Section E3.3)
The actual Unit 1 integrated control system testing completed during power operations was conducted in a well controlled manner with good evaluation of result (Section E8.1)
Plant Support
The licensee was effectively maintaining controls for radfoactive material and waste processing. (Section R1.1)
The licensee's water chemistry control program for monitoring primary and secondary water quality had been effectively implemented, for those parameters reviewed, in accordance with the Technical Specification requirements and the Station Chemistry Manual for water chemistr (Section R1.2)
The licensee had continued to effectively implement a program for shipping radioactive materials. (Section R1.3)
Effluent and environmental monitors were being maintained in an operational condition to comply with Technical Specification requirements and Updated Final Safety Analysis Report commitment (Section R2.1)
An unresolved item was identified to determine if a Unit 2 sample tube was constructed as shown on a design drawing. (Section R2.1)
The meteorological instrumentation had been adequately maintained and the meteorological monitoring program had been effectively implemente (Section R2.2)
Personnel involved with performing environmental and effluent surveys were maintaining current training qualifications. (Section RS)
Report Details Summary of Plant Status Unit 1 began the period in an outage due to once through steam generator tube leaks. The unit was placed on-line February 11, 1998. The unit increased power -and held at 65 percent power for nuclear instrument calibration and to investigate main feedwater oscillations. On February 14, 1998. the unit decreased power to 57 percent to lower main feedwater pump B flow and to complete emergency safeguards testing. The unit was taken off-line on February 15,.1998, due to failure of the 1HP-27 valve to close. The unit returned to service on February 19, 1998. and increased power to 70 percent to begin integrated control system testing. The unit increased power to 100 percent on February 21. 1998. Unit 1 experienced a failure of the 1D1 heater drain pump on March 1. 1998., and reduced power to approximately 85 percen The unit returned to 100 percent power on March 20. 1998, following replacement of the IDI heater drain pump and replacement of a cable connection for turbine control valve CV Unit 2 began the period at 100 percent power and commenced incremental power reductions on March 9, 1998, for a scheduled refueling outage. The unit was taken off-line on March 13, 1998. The unit ended the period in cold shutdown with outage activities in progres Unit 3 began and ended the period at 100 percent powe.
Review of Updated Final Safety Analysis Report (UFSAR) Commitments While performing inspections discussed in this report, 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 parameter I. Operations
Conduct of Operations 01.1 General. Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
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reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious: specific events and noteworthy observations are detailed in the sections-belo.2 Operations Clearances (71707)
The inspectors reviewed selected portions of the following clearances and block tag outs (BTO) during the inspection period:
98-0091 PM 1DW-87 and 1DW-89 Diaphragm Valves
98-0654 1CA-16 Repair
98-0712
.
1LP-124 Repair/Replace Leaking Tubing Nut
- BTO 3 Unit 2. Condensate System
BTO 13, Unit 2, Feedwater and Main Steam Lines The inspectors observed that the clearances were properly prepared and authorized, and that the tagged components were in the required positions with the appropriate tags in plac.3 10 CFR 50.72 Notification for Potential Inoperability of Valves Following an Appendix R Fire a. Inspection Scope (90712)
During the inspection period, the licensee made a notification to the NRC for potential inoperability of Appendix R valves following a postulated fire. The inspectors reviewed the notification issue for impact on the operational status of the facility and equipmen b. Observations and Findings On March 19, 1998, the licensee made a four-hour. non-emergency notification to the NRC in accordance with 10 CFR 50.72 requirements concerning potential valve failures due to a fire that could prevent alignment of low pressure injection (LPI).
During a review of Procedure OP/0/A/1102/24, Operational Guidelines Following a Fire in the Auxiliary Building. Turbine Building, or Vital Area. Revision 16, it was discovered that potential valve failures, due to a fire, could prevent alignment of LP This procedure provides the actions necessary to conduct an assessment of equipment availability following an Appendix R fire. No electrical check for damage was required by the procedure prior to closing the breakers for the valves required for operation of the LPI system. Closing the valve breakers prior to performing an electrical check of the wiring could result in the failure of the valves in the closed positio Procedure OP/0/A/1102/24 was placed on administrative hold. Interim guidance was established to notify work control to assist operations in the assessment of breaker and wiring conditions. At the end of the inspection period, the licensee was continuing to evaluate this issue and identifying appropriate actions for procedure changes to require the electrical check by Instrumentation and Electrical personne The licensee initiated Problem Investigation Procedure (PIP) report 0 098-1323 to track follow-up actions. The licensee plans to submit a Licensee Event Report (LER) on the subject (LER 50-269/98-08). Review of the adequacy of the procedure revisions will be conducted during review of LER 50-269/98-0 c. Conclusions The licensee reported a potential non-conservatism in the procedure for response to Appendix R fires in accordance with the requirements of
10 CFR 50.72. The compensatory actions established appeared to be adequat.4 Unit 2 Shutdown for Refueling a. Inspection Scope (71707)
On March 13. 1998, the licensee shutdown Unit 2 for refueling at the end of cycle (EOC) 16. The inspectors observed portions of the shutdown and reduced inventory activitie b. Observations and Findings The inspectors observed licensee operations during the initial portions of the cooldown from just before reactor shutdown until reactor coolant system (RCS) temperature was approximately 480 degrees Fahrenheit (F).
The operators took deliberate actions and properly used procedures. The inspectors also observed careful oversight by both senior reactor operators and licensee.managemen On March 20, 1998, the licensee entered reduced inventory operations when the operators reduced RCS level to less than 50 inches above the centerline of the hot legs. The inspectors were present in the control room and observed draining operations until the RCS level stabilized at 14 inches above the centerline of the hotlegs. The inspectors observed the following:
The unit was backfed from the switchyard with the unit auxiliar transformer, startup auxiliary transformer, and both Keowee units available
Containment closure was properly controlled with the equipment hatch closed
Two RCS level indications were available and calibrated, plus two additional ultrasonic level indicators on the hot and cold legs
All core exit thermocouples on the inadequate core cooling monitors were available and in service, plus two dedicated thermocouples on the operator aid computer
RCS makeup capability was available from both the borated water storage tank and the bleed holdup tank
Both steam.generators were vented through the primary manways The inspectors also observed the operators routinely referring to their procedure and careful oversight by both senior reactor operators and licensee managemen c. Conclusions The shutdown of-Unit 2 and reduced inventory operations were completed properly with deliberate operator action, good supervisory oversight, and good procedure adherenc Operator Knowledge and Performance 04.1 Operations Failure to Follow Procedure a. Inspection Scope (71707)
The inspectors reviewed problem reports, log entries, and interviewed personnel involved in several event b. Observations and Findings Removal of Hydrogen Recombiner Flanges On February 10. 1998, between 11:00 a.m. and 2:00 p.m., mechanical maintenance removed the flanges from and connected the hydrogen recombiner to permanently installed piping which was provided to connect the recombiner to the Unit 2 reactor building (RB). At 5:00 p.m., the operations test technician notified the Unit 2 control room that maintenance had removed the hydrogen recombiner flanges before operations had isolated.the piping as required by Procedure PT/2/A/0160/004, Hydrogen Recombiner Operability and System Piping Flow Test, Revision 4 tet 1 This step states to close or verifyclosed seven containmen isolation valves prior to connecting the recombine In fact, the flanges had been removed prior to operations isolation of the piping. This sequence resulted in an open path from the R Operations subseguently isolated the line and verified a pressure increase in the B to show there had not been an unmonitored release via the recombiner piping. The inspectors reviewed the graphical trend data that supported the fact that a negative pressure was present in the RB during the period that the flanges were off. Operations also verified the operability of the RB isolation valve that would have isolated the piping on an engineered safeguards signa PIP 2-098-0647 was initiated for followup and corrective action Operations and maintenance personnel failed to effectively communicate the status of the work. This resulted in removal of the flanges prior to isolation of the line by operation Personnelbinvolved were counseled on effective communications techniques, procedure enhancements were discussed, and a root cause evaluation was initiate De-Boration Missed Step On February 10, 1998. at approximately 11:30 p.m., a reactor operator was performing OP/1/A/1103/04, Soluble Poison Concentration Control, Revision 44, Enclosure 3.17, Operation of 3B Deborating Demineralizer to De-lithiate Unit 3. The operator failed to perform Step 2.2.3 due to inadequate self-checking. This step would have opened 3CS-32, the inlet
to 3B deborating ion exchange This resulted in the lifting of the letdown relief valve. Operations opened 3CS-32, verified stable plant status, and initiated PIP 3-098 065 The event was reviewed with operations personnel on each shift, the individual was counseled for proper self-checking techniques, and management expectations on event free human performance were reiterated to the Operations Shift Manager Mis-Operation of a Feedwater Pump On February 15, 1998. at 11:11 p.m., while performing a Unit 1 shutdown for repairs to valve 1HP-27, the reactor operator misread a step in Procedure OP/1/A/1102/10, Controlling Procedure for Unit Shutdow Revision 135, Enclosure 4.1B. Hot Shutdown Configuration Alignmen The operator inappropriately reduced main feedwater pump 1A demand instead of reducing the Integrated Control System main feedwater master hand/auto station. This caused a level decrease in the once through steam generators (OTSG) to the dry out protection actuation leve This resulted in an automatic start of the motor driven emergency feedwater (MDEFW) pumps. Operations restored normal feedwater level, stopped the MDEFW pumps, and initiated PIP 1-098-0737. The individual was counseled for proper self-checking and event free human performance technique The above events are considered non-repetitive, licensee identified and corrected violations that are being treated as a non-cited violation (NCV) consistent with Section VII.B.1 of the NRC Enforcement Polic This is identified as NCV 50-269,270,287/98-02-01: Failure to Follow Procedure-Three Example c. Conclusions A non-cited violation was identified with three examples for failure to follow procedur.2 Inadeauate Review of the Removal and Restoration (R&R) Book for Startup a. Inspection Scope (71707)
The inspectors reviewed procedures, problem reports, and interviewed personnel involved in the inadequate review of the R&R book prior to Unit 1 startu b. Observations and Findings On February 11, 1998. at 11:34 p.m., a senior reactor operator (SRO)
reviewing the R&R book, Procedure OP/0/A/1102/06. Removal of Station Equipment, Revision 32, discovered that the emergency cooling water supply to the high pressure injection (HPI) pumps for Unit 1 was isolated. Selected Licensee Commitment 16.9.9 requires these valves to be open to allow the stati.on auxiliary service water pump to supply
emergency cooling whenever the unit is above 250 degrees F. The uni had exceeded 250 degrees F on February 8, 1998. at 3:24 a.m., with the supply isolate On February 12, 1998, at 10:00 a.m., a non-licensed operator (NLO)
discovered the normal and emergency heat trace circuits for the Unit 1 concentrated boric acid tank (CBAST) deenergized for repair per the R&R procedure. This rendered the CBAST inoperable. The unit was at 65 percent power, which per Technical Specification (TS) 3.2 placed the unit in a 72-hour Limiting Condition for Operation (LCO). The CBAST pump and associated circuits had been tagged out on February 9, 199 for pump repair while the unit was in hot shutdown. Operations re energized the circuits, demonstrated flow in the affected line, and initiated PIP 1-098-071 Individuals involved were counseled and-management expectations were reiterated to other operations personnel that also review the R&R boo Both events are being reviewed for human performance issues and to verify the root cause Procedure OP/1/A/1102/01, Revision 219, states to review the R&R book for any items which affect unit heatup. These two examples are considered non-repetitive, licensee identified and corrected violations that are collectively being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50 269/98-02-02: Inadequate Review of Removal and Restoration Book Two Example c. Conclusions Failure to complete an adequate review of all items necessary for Unit 1 startup resulted in a non-cited violatio.08 Miscellaneous Operations Issues (92901)
08.1 (Closed) Unresolved Item (URI) 50-269,270.287/97-18-03: Standby Shutdown Facility (SSF) Diesel GeneratorOperation The inspectors reviewed PIP 4-098-0597 and interviewed the system engineer on the SSF diesel generator engine tachometer and turbo-charger oil pressure discrepancies. Based on these reviews, no items were identified for additional followup. This item is close.2 (Open) URI 50-269270,287/98-01-01:
Nuclear Safety Review Board (NSRB)
Review of 10 CFR 50.59 Safety Evaluations The inspectors attended the NSRB meeting held at the Oconee Nuclear Station on February 17 and 18, 1998. The board briefly discussed review of 10 CFR 50.59 Safety Evaluations. The board agreed that the current practice for reviewing 10 CFR 50.59 safety evaluations (i.e., one member of the board reviews each safety evaluation) met TS requirements. NSD
.309, Nuclear Safety Review Board, Revision, 5 allows 10 CFR 50.59 safety
evaluation to be reviewed by the NSRB staff. If the staff determines any are not significant, the staff is authorized to conclude that no formal review by NSRB members is required. Pending resolution of the differences between NSD 309 and the TS, this item will remain open. The board also discussed that the NSRB TS would be relocated to the Duke Energy QA Topical Report as part of the Oconee Improved TS submitta I Maintenance M1 Conduct of Maintenance M1.1 General Comments a. Inspection Scope (62707. 61726)
The inspectors observed all or portions of the following maintenance activities:
TT/2/A/251/07 LPI Cooler Performance Test, Revision 0
WO 98012267-01 Unit 2, Engineering Safeguards Digital Channel Test 1 and 2 (2HP-27 Valve Stroke)
WR 98023085 Engineering Safeguards Analog Channel Test (PIP 98-1099)
PT/1/A/0600/025 Motor Driven Emergency Feedwater Pump ARC Valve Test, Revision 0
OP/1&2/A/1104/06 Spent Fuel Cooling System. Enclosure 3.6. Pool Level Draining, Revision 58
IP/0/A/0203/001A LPI System BWST Level Calibration, Revision 19
PT/2/A/0152/12 LPI System Valve Stroke Test. Enclosure 13.1 LPI Valve Stroke at Power, Revision 4
OP/0/A/1510/016 Miscellaneous SFP/Canal Operations, Revision 3
IP/0/B/0276/002 ATWS Mitigation System AMSAC/DSS Logic Tes Revision 11
PT/1/A/0152/021 Hydrogen Recombiner Drain System Valve Stroke Test, Revision 0
PT/1/A/0600/012 TDEFW Pump Test, Revision 55
ON-OAC-84 Change Imbalance Limits IP/0/B/0261/001C Pump Bay Level and Intake Screen Delta P Instrument Calibration, Revision 20
WR 98021210-01 1LP-124 Repair/Replace Leaking Tubing Nut
TT/1/B/0326/001 ICS/NNI Transient Testing at Power, Revision 0 b. Observations and Findings The inspectors found the-work performed under these activities to be thorough. All work observed was performed with the work package present and in use. Technicians were experienced and knowledgeable of their assigned tasks. The inspectors frequently observed supervisors and system engineers monitoring job progress. Quality control personnel were present when required by procedur When applicabte appropriate radiation control measures were in plac c. Conclusions The inspectors concluded that the maintenance activities listed above were completed adequatel M1.2 Unit 2 Turbine Driven Emergency Feedwater (TDEFW) Pump Hotwell Suction a. Inspection Scope (62707)
The inspectors reviewed the circumstances surrounding an inadvertent puncture of the Unit 2 TDEFW pump hotwell suction lin b. Observations and Findings On February 11, 1998, while anchoring.a pipe hanger to the turbine building basement floor, licensee personnel drilled into the buried pipe connecting the Unit 2 hotwell to the suction of the Unit 2 TDEFW pum Air inleakage and a significant increase in condenser air ejector offgas flow was immediately observed. Licensee personnel installed a rubber plug in the hole and covered it with a rubber mat and plywood cover as a temporary repair. On February 13, 1998, the inspectors questioned whether or not the repair involved a modification. On February 14, 199 the temporary repair was converted to a temporary modification (TM).
The TM included a screening against 10 CFR 50.59 and determined that a safety evaluation was not needed because the affected pipe was not described in the safety analysis report. The licensee also initiated PIP report 2-098-0691, which included an evaluation indicating that the pipe remained operabl The inspectors reviewed the TM, PIP report, and operability evaluatio The inspectors also reviewed Nuclear Station Directive (NSD) 301, Nuclear Station Modifications, Revision 13 and NSD 209, 10 CFR 50.59 Evaluations, Revision 7. The inspectors determined that the operability evaluation was properly done commensurate with the safety functions of the TDEFW pump hotwell suction pipe. The inspectors also determined that the review against 10 CFR 50.59 was done properly. However, Section 301.7 of NSD 301 defined a temporary modification as a physical change of a temporary nature to a station's structures, systems, or components. The inspectors determined that the temporary modification was installed after questioning by the inspectors. This indicated a lack of rigor in applying the modification process and was a failure to
follow NSD 301. This constituted a violation (VIO) of 10 CFR 50 Appendix B, Criterion V and is identified as VIO 50-270/98-02-03:
Failure to Implement Temporary Modification In a Timely Fashio c. Conclusions The inspectors identified a violation for failure to follow the nuclear site directive for modifications when repairing the Unit 2 turbine driven emergency feedwater pump hotwell suction lin M1.3 Pressurizer Surge Line (PSL) Drain Line Vibration (Unit 1)
a. Inspection Scope (62700)
The inspectors reviewed the adequacy of the licensee's investigation and evaluation of a vibration phenomenon on the Unit 1 PSL drain line that occurred during plant heat-up on February 8, 1998. The governing codes were the American National Standard Institute (ANSI) B31.7, 1968 Edition and the American Society of Mechanical Engineers (ASME), OM-SG. 1990 Edition, Part b. Observation and Findings Background On February 9, 1998, the inspectors reviewed the repair and replacement of a PSL drain line that had been previously addressed in NRC nspection Report (IR)
50-269,270,287/97-18. Through discussions with cognizant engineering personnel and review of PIP report 1-098-0608 (dated February 10, 1998) and other documents, the inspectors ascertained the following information. During plant heat-up on February 8, 1998. the licensee discovered that the PSL drain line was vibrating excessively with a movement that was approximately V2-inch in either direction. The licensee's preliminary engineering evaluation disclosed that the vibration was unacceptable and suggested that the drain line was subject to failure at about one million (E6) cycles of sustained high vibratio However, the licensee's re-evaluation showed that the endurance limit of the replacement stainless steel piping was in the area of Eli cycles rather than the E6 cycles used in the preliminary evaluation. In addition, the engineering evaluation determined that plant heat-up events, and a 35 Hertz vibration observed on the reactor coolant pump stand/platform was probably a function of reactor coolant loop heat-up and pressurizatio Corrective Actions and Monitoring A list of precautionary measures planned or taken included monitoring of plant configuration and above normal vibrations, liquid penetrant testing of designated welds on the drain line, development of a contingency plan should the line experience sustained excessive vibrations, and redesign of the subject piping in time for modification during the next refueling outag On February 15, 1998. Unit 1 was brought to a hot shutdown condition to perform valve repairs on the feedwater and HPI systems. During plant heat-up, after these repairs, the licensee indicated that the subject line experienced similar vibrations for a short period of time. The vibrations diminished and the line returned to normal as the plant heated up to steady state condition c. Conclusion The licensee's response to the Unit 1 pressurizer surge line drain line vibration phenomenon was appropriate. Maintenance and engineering provided good coverage of the issue. Evaluation of the problem and the corrective actions taken and planned were consistent with plant safety and code requirement M1.4 Unit 2 LPI Cooler Test a. Inspection Scope (62700)
The inspectors assessed the adequacy of the 2A and 2B LPI cooler test performed in accordance with Procedure TT/2/A/0251/067, Revision 1. The governing TS was 4.5.3.1, Containment Heat Removal Capabilit b. Observation and Findings This test was performed while Unit 2 was at power and in response to the TS 4.5.3.1 requirement that containment heat removal capability be tested on a refueling basis to verify that it can be maintained during post-accident conditions and that LPI cooler fouling rate be determined in order to establish if a more frequent test was require In order to perform this test, the licensee heated the borated water storage tank (BWST) and used it as the heat source to test the LPI coolers' heat transfer capabilities. The licensee's unreviewed safety question (USQ) evaluation dated January 30, 1998. addressed the following areas of concern: effects of increasing the low temperature set point of the BWST; recirculating the water in the BWST; and installing and connecting temporary instruments to existing instrument The evaluation concluded that the test did not put the plant in an unanalyzed condition and would not adversely affect the LPI syste On February 10, 1998. the inspectors observed the above-mentioned test and noted that procedure adherence was maintained and that test equipment was identified and calibrated. Preliminary results showed that both coolers exhibited stable heat transfer capabilities from the tube side and shell side and that calculated heat removal capacity (based on a 65 degrees F temperature) was greater than that required for accident mitigation. However, preliminary test calculations also showed that the film coefficient and fouling in the "A" cooler were relatively high under test conditions. To evaluate this condition further, the licensee used previous test results and related testing parameters to project the expected levels of fouling and the film coefficient value Through this re-evaluation, the licensee concluded that the "A" cooler
was not fouled. The high fouling numbers were attributed to the low LPSW flow rate utilized for the test. Test objectives were met and system restoration was accomplished in a timely manne c. Conclusion The Unit 2 LPI cooler test was performed in a well planned manner, the applicable procedure was followed, personnel were well qualified to perform their assigned tasks, and that results showed that Unit 2 LPI coolers 2A and 2B are capable of performing their desfgn'functio M1.5 Locked-Up Grinell Hydraulic Snubber On 1B2 Reactor Coolant Pump Motor a. Inspection Scope (62700)
The inspector reviewed the adequacy of corrective actions taken to restore the subject snubber back to good working condition. Work was performed under applicable maintenance procedures MP/O/A/1800/022, evision 5 and MP/O/A/3018/002, Revision 2 b. Observation and Findings On February 8, 1998, while Unit 1 was at hot shutdown, the licensee's inspection of the reactor coolant pump motor hydraulic snubbers revealed that snubber S/T No. 1-50-0-66A-RCPM-S12 was in a rigid condition and concluded that the snubber was locked-up. Following this assessmen Unit 1 entered into a 72-hour LCO. At approximately 9:30 p.m. on February 9, 1998, the inspectors accompanied the licensee's technical support personnel and the vendor's (Grinnell) representative to the reactor containment building to inspect the snubber in the 1B2 cavit The licensee's technical support personnel and the vendor inspected the snubber and determined that it was not locked-up as originally believed, but that it was binding on one of the end brackets. This problem was corrected by rearranging the two different size spacer washers on the rod ends of the snubber. More specifically, by placing the larger of the two spacers on the bottom of the rod-end, the snubber was brought closer to level and the binding problem was corrected. Through this inspection effort and the corrective action taken, the licensee concluded that although this binding was undesirable, it would not have prevented the snubber from performing its design function since it was not locked-up or inoperabl c. Conclusion The licensee's response to the apparent snubber lock-up problem was well-planned and carried out in a timely manner. Soliciting assistance from the vendor resulted in the correct diagnosis of binding on one of the end brackets and a quick solution to the proble M1.6 Inservice Inspection (ISI) of Safety-Related Welds and Components (Unit 2)
a. Inspection Scope (73753)
The inspectors verified by observation and document review that nondestructive examinations of safety-related welds were performed in accordance with the licensee's implementing procedures and applicable Code requirements. The controlling code for Oconee's ISI activities was ASME Code Section XI, 1989 Edition with no addenda, (Code).
Procedures used for examinations observed were as follows:
NDE-60, Rev. 11 Ultrasonic Examinations (UT) of Similar Metal Welds in Wrought Ferretic and Austenitic Piping
NDE-35, Rev. 17 Liquid Penetrant Examination
NDE-640. Rev. 1 UT Using Longitudinal and Shear Wave Straight Beam Techniques
NDE-690. Rev. 0 UT of the HPI, Nozzle Inner Radius at Oconee Nuclear Station NDE-960, Rev. 1 UT of the HPI System Piping Welds and Base Material at Oconee Nuclear Station
ASME Code Case N-525 and Section XI. 1992 Edition with Addenda through 1993 Appendices VIII and VIII-210 b. Observation and Findings Scheduled Inservice Inspection The inspectors reviewed ISI activities scheduled for the upcoming refueling outage (RFO 16) which was the second outage of the first period of the third ten-year interva Examinations performed on safety-related welds were identified in the licensee's ISI Database Management System. The inspectors selected at random several ISI examination categories and verified by review that the number of welds selected by the licensee for examination during this outage were consistent with Tables IWB.-and-IWC 2500-1 of the Code. Examination categories selected for this review were as follows:
B-A Pressure Retaining Welds in Reactor Vessel
B-D Full Penetration Welds of Nozzles in Vessels
B-J Nominal Pipe Size less than 4-inch and greater than 4-inch, branch connections and socket welds
- B-F Pressure Retaining Dissimilar Welds in Nominal Pipe Size less than 4-inch and greater than 4-inch and branch connections
C-F Pressure Retaining Welds in Austenitic Stainless Steel or High Alloy Piping In addition to this work effort, the inspectors observed ISI examinations performed on the following welds:
Item Weld Examination Joint description C05.021.030 2-51A-17-147 UT Valve 2HP-148 to
.030A PT elbow C05.021.031 2-51A-17-158 UT Elbow to Elbow
.031A PT C05.021.096 251A-28-40A UT Valve 2HP-129 to
.096A PT Pipe C05.021.034 2HP-220-14 UT Pipe to Tee
.034A PT On item C05.021.034 above, the ultrasonic examination identified a recordable spot indication that appeared to be outside of the area of interest. However, the licensee indicated their intention to do followup work to determine its nature and document it for future reference. This was the first time that these welds were subjected to examination per the ISI program. The revision to include four-inch diameter piping was required by the updated edition of the Cod The inspectors reviewed the construction radiographs of the subject welds for Code acceptability and agreed with the licensee's findings that no evidence of rejecta ble indications could be detected. The licensee's inspection plan was to re-examine the subject weld with a smaller transducer and see if the indication could be characterized better. From this work observation and associated record review, the inspectors determined that the above welds were adequately examined and that the Code required information and examination results were documented and evaluated satisfactorily. Examiners were adequately trained and knowledgeable, and performed their assigned tasks with attention to detail and code requirements. Equipment and materials used were properly identified, calibrated and traceable to certification document High Pressure Injection Nozzle Component Examination Per Generic Letter (GL) 85-20 Requirements (Units 1. 2 and 3)
By review of licensee documents provided for review, the inspectors ascertained that by letters dated August 6, 1997, September 10, 1997, October 23. 1997, and January 7, 1998, the licensee submitted a revision to the Oconee Third Teh-Year ISI Program. This revision was made to
enhance and clarify the general requirements of the licensee's Augmented Inspection Program, and to address the requirements of GL 85-20 regarding the examination of HPI system nozzle components during regularly scheduled refueling outages. By letter dated October 23, 1997. the NRC staff approved the revision to the Oconee ISI program and requested that the licensee commit to perform specified examinations of the subject components. Accordingly, the licensee committed to perform all future volumetric and surface examinations of the HPI nozzles, HPI nozzle inner radii, and safe-end to HPI nozzle welds. These examinations would be performed in accordance with the requirements of the 1992 Edition with the 1993 Addenda of the ASME Code,Section X Appendix VIII. or with the requirements of the applicable Code using calibration blocks with cracks that simulate the type of crack observed in Oconee Unit 2. As such, the licensee procured precracked calibration blocks for use on the.HPI nozzle inspection Nozzle components subject to examination during planned outages are as follows:
UT nozzle inside radius (knuckle area)
UT of safe end base metal (area between nozzle safe end weld and safe end to pipe weld)
0*
UT of safe end to pipe weld and of the base metal for the pipe
UT of pipe to valve weld (2HP-127, -126. -153. & -152)
RT area between nozzle to safe end weld and safe end to pipe weld (this is to look at thermal sleeve rolled area)
The completed and scheduled inspections by outage, for all three units, are as follows:
Unit 2 Forced outage completed 5/97
Unit 2 Scheduled outages RFO.16 (3/98). RFO 18 (4/1), RFO 20(4/04)
Unit 3 Forced outage completed 5/97
Unit 3 Scheduled outages RFO 17 (9/98), RFO 19 (9/01), RFO 21 (9/04)
Unit 1 Forced outage completed 6/97 (credit taken for RFO 17 augmented exams)
Uni Scheduled outages RFO 19 (11/00), RFO 03)
In reference to inspections performed on the subject nozzle welds during the Unit 1 June 1997 forced outage, the inspectors reviewed the following
- radiographic film and ultrasonic examination records to determine compliance to Code requirement Isometric Component Weld Drawing Description Comments 101 1-RC-201 Safe-end to pipe, Repaired twice to Rev. 3 pump 1B1 side remove weld fabrication defects 102 1-RC-201 Safe-end to pipe, No repairs Rev. 3 pump 1B2 side acceptable by radiography 154 1-RC-199 Safe-end to pipe, No repairs Rev. 5 pump 1A1 side acceptable by radiography 161 1-RC-200 Safe-end to pipe, Acceptable root Rev. 4 pump 1A2 side geometry verified by radiography c. Conclusion Segments of the licensee's third ten-year interval of the ISI program that were reviewed, complied with Code requirements. ISI examinations observed were performed in a satisfactory manner. Fabrication and examination records of HPI nozzle component welds were consistent with code requirements and licensee commitments. Technicians were well trained and had good knowledge of plant equipment and procedural requirements. The licensee's evaluation of inspection results were documented with accuracy and clarit.M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Spent Fuel Pool (SFP) Foreign Material Exclusion (FME) Practices a. Inspection Scope (62707, 71750)
The inspectors observed maintenance activities and FME practices during diving operations in the SF b. Observations and Findings On February 23. 1998, the inspectors observed diving operations in the Unit 1 and 2 SFP for repair of a Unit 1 fuel grapple. The inspectors identified a %-inch ratchet, three 3/4-inch sockets, one 1 1/8-inch socket, two %-inch pull bars, multiple pieces of stainless steel shim material, and one nut splitter inside the FME area. Maintenance personnel had not included these items in the control lo The inspectors discussed the issue with personnel at the SFP. An inventory of tools and material was compl eted and the log was correcte.16 Operations and maintenance management were informed and problem report 0-098-0876 was initiated. Licensee inspection of the area also identified a loose socket head screw on the grapple mounting plate. It was not part of the grapple and during retrieval fell into a dummy guide assembly. Problem report 5-098-0874 was initiated for trending purpose Previously, on February 17, 1998, a stainless steel rod approximately 8 inches long was identified in location J-82, in the Unit 1 and 2 SF The object was found when attempting to insert an assembly into that location. The licensee could not identify the source of the rod and problem report 5-098-0781 was initiated. On February 19, 1998, the diver identified a second stainless steel rod protruding from the intersection of four empty racks. The licensee could not identify the source of the object. Problem report 5-098-0826 was initiated to track corrective actions related to retrieval and identification of the objec A licensee maintenance assessment of the FME program was initiated on March 9. 1998. for followup and corrective action. The licensee also initiated an examination of all empty racks in the SFP for other objects. This examination is documented in problem report 5-098-102 The examination was completed on March 3, 1998. and revealed the following: a 1 foot long piece of coaxial cable, a roll of duct tape, eight small nuts, and one small piece of copper tubin The inspectors reviewed NSD 104, Housekeeping, Material Condition, and Foreign Material Exclusion, Revision 13. NS 104 requires in part that when parts, tools, or other items can be dropped into a system, documentation of tools and materials that enter or leave the foreign material exclusion area be performed. Procedure OP/0/A/1510/01 Miscellaneous SFP/Canal Operations. Revision 03, Enclosure 3.4, Diving Operations in SFP/Canal, states to ensure ALL material entering SFP control area is documented. This procedure states in part that the requirements of NSD 104 SHALL be in effect for all activities performed under this procedur Failure to enter the tools into the control log on February 23, 1998. is a violation of Procedure OP/0/A/1510/016, and is identified as VIO 50 269,270/98-02-04: Failure to Follow Procedure for Foreign Material Contro c. Conclusions The inspectors identified a violation of procedural requirements for foreign material control practices during maintenance in the Unit 1 and 2 spent fuel poo III
M2.2 Material Condition and Housekeeping (Unit 1)
a. Inspection Scope (62707)
During observation of the stroke test of motor operated valve 1HP-27 while Unit 1 was at 100 percent power, the inspectors observed several anomalies in the material condition of the Unit 1 west penetration roo b. Observations and Findings The anomalies identified were as follows:
Valve 1HP-286. a reactor coolant pump seal injection block valv was observed to have loose packing retaining nuts (i.e., lacked proper adjustment and thread engagement). Both gland follower studs were not engaged with both packing retaining nuts by two and one half turns. The licensee issued work request 98009664 to tighten and adjust the packing nuts and issued PIP report 1-098 093 The valve had been replaced under modification ONOE-10202 and work order (WO) 97022056-01 during the recent outage. As part of the replacement, valve packing adjustment instructions were not issued in the replacement package. The engineering instruction minor modification package sheet that was to control the check of the valve packing and provide ad ustment instructions was not appropriately annotated. Walk down of the completed work during the close out process had not identified the condition. The Anderson, Greenwood and Compan valve did have an internal bellows that was the primary pressure oundary. The packing was a secondary pressure boundary. The modification was intended to replace obsolete valve types and reduce packing leakage problem Site Directive 2.2.1 Minor Modification Program, revision date August 28, 1997. provided general instructions for the proces Section 3.10. Procedures/Engineering Instructions, of this procedure and indicated, in part, that: "If an existing procedure is used, it shall contain detailed instructions sufficient to perform the Quality Assurance (QA) Condition 1 activities needed to perform the modification. Some examples of the procedures are as follows: field run cable supports, welding, support/restraint installation, cable pulling, breaching fire barriers, and concrete anchor installation. Engineering instructions may be used to control the flow of the QA 1 minor modification packages, but in this situation, all QA 1 aspects of the implementation must be performed by existing station procedures.'
The engineering instructions mentioned above had a question listed that said:
"Packing check required?", with "yes" and "no" boxes on the same line. The instruction further stated that: "the appropriate procedure will be specified by the WMS [work management system]
Planner on the work order."
With the box marked "no," the planner did not invoke welding procedure requirements for checking the loosely installed packing following valve weld-in. The welding procedure was used to install the new valve, and without specifically invoking the packing section of that procedure, the packing check was not performed. In this case, the engineer preparing the engineering instruction checked the wrong box. Further, the engineering instruction did not address the specifics of packing adjustmen Because the packing was a secondary pressure boundary, it should have been addressed on such an important subsystem The inspectors concluded from the above that the licensee failed to provide adequate or correct modification instructions due to failure to follow an engineering site directive procedure. The failure to follow the minor modification procedure is a violation and is identified as VIO 50-269/98-02-05:
Failure to Follow Modification Procedur Valve 1HP-149 had one of two packing retainin nuts not properly engaged with its retaining stud. Unlike 1HP-286 that had the fo lower studs entering the valve body, the gland follower studs for this valve were double nutted with the studs not threaded into the valve body but had a set of fasteners behind ears on the bod Work request 98009665 was written and accomplished to establish proper stud engagement. PIP report 1-098-0944 captured the details of the equipment conditio At the end of the inspection period, the licensee had not completed the past operability evaluation on the valve as discovered condition. This issue is identified as Unresolved Item (URI) 50-269/98-02-06:
Improperly Installed Valve Packing Gland Fastener Borated water was on the floor of the penetration room beneath valves 1HP-149, 1HP-150 and 1HP-151: Deficiency tags were hanging at the valves. The leakage did not appear to be active with the injection line flowing at normal system pressur The licensee confirmed the no active leakage status of these valves and that the valve subcomponents were stainless steel material. A feedwater valve above the three valves had been identified as the leakage source and earlier leakage from one of the three HP valves had contributed the boron to the standing fluid on the floor of the space. The licensee had begun a new leakage control program that had yet to reach this space/are The deficiency tags had been in place since December 1995, but the licensee had not elected to take action to finalize work on 1HP 150 and 1HP-151. The tags were written based on one valve leaking by its seat and one valve having a past packing leak. The cutout and replacement of the valves were verified to be scheduled for the next Unit 1 refueling outag Grey tape was on the stainless steel valve body of LWD-345. The valve is a vent on the "B" train HPI line. The licensee removed
the tape and tested it for halides. No halides were found, but the licensee had no procurement or in-use controls on the grey tape. The tape could have been purchased with unacceptable levels of chlorides. This issue is further discussed in section M As a side note, another inspector reported a Unit 3 tape finding to the licensee and this also returned a negative halide resul General housekeeping in this space was poor. Dirt, loose tools, loose objects such as tubing and debris were evident, some of which were lying in cable trays and on top of equipment. A Quality Control inspector had been with the inspector for the 1HP-27 valve stroke. At the NRC inspector's suggestion, he wrote down other minor housekeeping and material condition problems to have them addressed. At the time of discovery, the above conditions were reported to operations and maintenance managemen c. Conclusions Material condition in the Unit 1 west penetration room was deficient. A violation was identified for failure to follow a minor modification instruction for adequate packing gland adjustment on valve 1HP-286. An unresolved item was identified for past operability concerns for improperly installed packing gland followers for valve 1HP-14 M2.3 Material Condition and Housekeeping (Unit 2)
a. Inspection Scope (62700)
The inspectors determined by observation and document review, the adequacy of the licensee's material condition and housekeeping practices. The licensee's controlling documents were Nuclear System Directive (NSD) 104, Revision 13, Housekeeping, Material Condition and Foreign Material Exclusion; Power Chemistry Materials Guide Progra Revision 25, and Material Safety Data Sheet (MSDS) 359 b. Observations and Findings The inspectors reviewed the above-mentioned documents and procedures and inspected the Unit 2 west penetration room and HPI room 58 to verify that procedural requirements with respect to the control of coatings/paint, lagging material, lagging adhesive and gray adhesive (duct tape) on chloride sensitive stainless steel components; and loose material/debris, including lube oil leaks. In reference to the presence of lagging adhesive CP-50 on components, the inspectors observed on March 4, 1998, that this materia] was in permanent contact with several components made of stainless steel material, including piping, valves and fasteners located in the Unit 2 west penetration room and HPI room 5 By review of Duke Power Chemistry Materials Guide Program. SQDA Plan
"D".
Revision 25, the inspectorsascertained that the subject document required that materials designated for use in any plant application involving stainless steel components be analyzed for impurities and
approved for use as specified. The inspectors noted that lagging adhesive CP-50 had been applied on stainless steel components without first being analyzed for impurities and approved for use in specified applications by the licensee's chemistry group. This failure to implement procedure requirements was identified as example one of VIO 50-270/98-02-07: Failure to Implement Procedural Requirements Relative to Material Condition and Housekeeping Practices-Two Example Within the area of material condition and housekeeping, the controlling procedure, NSD 104, Revision 13, requires that the'use, location and deployment of materials shall be controlled to prevent conditions that wi 1 adversely affect quality; that mechanical components shall be properly maintained to reflect-no degree of neglect; that area owners are responsible for ensuring that material condition/housekeeping measures were working effectively and initiating corrective measures for all related problems. The inspectors noted that material condition and housekeeping requirements were not being implemented in the Unit 2 west penetration and HPI 58 rooms in that paint smudges and paint splatter were observed on stainless steel piping, valve bodies, valve motor operator covers, hand wheels and electrical cable; lagging material deposits were observed on a wall mounted instrument line support: the motor-stand of HPI pump 2B exhibited a film of oil on its horizontal surface: gray adhesive (duct tape) had been used to secure lagging on piping and over small bore..drain lines and significant amounts of coating had peeled off equipment and floors. In addition, duct tape was observed being used to secure insulation on stainless steel piping and for other purposes on small bore piping. This failure to implement procedure requirements was identified as example two of VIO 50-270/98 02-07: Failure to Implement Procedural Requirements Relative to Material Condition and Housekeeping Practices-Two Examples. The inspector discussed these findings with the license's technical support personnel and management. The licensee wrote PIP 0-098-1037 dated March 4, 1998, in order to document the findings and corrective actions planned and taken on the problems identifie c. Conclusion The licensee's failure to implement procedural requirements on material condition and housekeeping practices on safety-related components and in the areas housing these components and structures was identified as a violatio M4 Maintenance Staff Knowledge and Performance M4.1 Unit 3 Component Cooling (CC) Flow Calibration a. Inspection Scope (62707)
The inspectors reviewed the circumstances surrounding an inadvertent start of the standby Unit 3 component cooling pump during flow calibration *I
b. Observations and Findings On February 25, 1998, with one CC pump normally operating, instrument technicians removed from service the transmitter for total component cooling flow, resulting in an inadvertent start of the standby pum The technicians were performing as-found calibration checks in accordance with Procedure IP/B/0240/001C. Component Cooling Pressure, Flow, and CRD (Control Rod Drive) Filter Differential Pressure Instrument Calibration, Revision 12. The first step for the calibration of the flow transmitter required the standby pump control switch to be placed in off to prevent a standby pump star Due to poor communications, technicians at the transmitter isolated and vented the transmitter before technicians in the control room asked for the standby pump to be turned off. The licensee documented the action in PIP report 3-098-0919. counseled the involved supervisor and technicians, and referred the matter to the Organizational Effectiveness Grou The inspectors interviewed appropriate licensee personnel, reviewed the procedure, and reviewed the PIP report. The inspectors determined the actions leading to the inadvertent start of the standby CC pump were a violation of 10 CFR 50 Appendix B. Criterion V for failure to follow Procedure IP/B/0240/001C: The inspectors also determined that sensitivity to procedural compliance and proper communications was heightened by the licensee's subsequent corrective action Accordingly, this non-repetitive. licensee-identified, and corrected violation is being treated as an NCV, consistent with Section VII.B.1 of the Enforcement Policy. This is identified as NCV 50-287/98-02-08:
Failure to Follow Calibration Procedur c. Conclusions The inspectors concluded that corrective actions as a result of an inadvertent start of the Unit 3 standby CC pump heightened the sensitivity of instrument technicians to procedural compliance and proper communications. The inspectors considered this a positive result of the licensee's recovery pla An NCV was identified for failure to follow procedure when calibrating a component cooling flow transmitte III. Engineering El Conduct of Engineering E1.1 Valve 1HP-27 Failure to Close Inspection Scope (62707, 37550)
The inspectors reviewed the circumstances surrounding the failure of valve 1 HP-27 to close on a signal from the control roo b. Observations and Findings On February 14, 1998, during engineered safeguards (ES) performance testing on Unit 1, motor operated HPI valve 1HP-27 failed to close properly. The licensee subsequently entered TS 3.3.1 and on February 15, 1998, shut down and cooled down Unit 1 to less than 350 degrees The licensee notified the NRC in accordance with 10 CFR 50.7 The licensee removed the actuator, lubricated the valve stem and stem nut, and replaced the packing. The licensee reinstalled the actuator and satisfactorily performed a static thrust test on the valve. The licensee initiated three PIP reports (1-098-0730. 1-098-0765 1-098 0798) to track corrective action Licensee motor operated valve (MOV) engineering personnel determined the valve failed to close with 2100 pounds per square inch gauge (psig)
downstream pressure in the pipe. Acting against this pressure, the close direction torque switch opened and stopped the valve from going fully closed. The licensee further determined the design basis assumptions for the valve resulted in a lower calculated stem load than may really exist under worst case conditions. The design of all HPI injection and crossover valves (1,2.3HP-26. 27. 409. 410) was based on the worst case differential pressure across the valve. Due to valve design, the worst case static pressure acting under the seat would result in a greater force to overcome than previously modeled with the worst case differential pressure. The licensee had used 200 psig for downstream pressure, but actual worst case would be 2800 psi Engineering personnel reviewed thrust data for all HPI system injection and crossover valves and determined all to be operable. The licensee also performed a past operability evaluation for valve 1HP-27 and determined that, even though the valve would not throttle under some conditions, the HPI system would have performed its functio The inspectors reviewed the PIP reports and interviewed engineering personnel involved with the operability determinations for all HPI injection and crossover valves. The inspectors determined that the licensee used an acceptable approach to determine the current operability of HPI system injection and crossover valve Pending NRC review of the past operability evaluations, the circumstances surrounding this issue will be tracked as URI 50-269/98 02-09:
Failure of Valve 1HP-27 to Close, Conclusions The inspectors concluded the licensee used an acceptable approach to determine the current operability of the HPI system injection and crossover valves after the failure of valve 1HP-27 to clos However, this issue was left unresolved pending further review of the
- past operability for valve 1HP-27 by the license E3 Engineering Procedures and Documentation E3.1 Operability of the Borated Water Storage Tank (BWST) and Reactor Building Emergency Sump (RBES) Due to Instrumentation Errors a. Inspection Scope (37550)
The inspectors reviewed documents, interviewed personnel, observed instrument calibrations, and attended meetings relating to instrument inaccuracies in the BWST and RBES level instrument b. Observations and Findings Between November 10, 1997, and December 11, 1997, a licensee Self Initiated Technical Audit (SITA) of the HPI and LPI systems identified items requiring engineering followu Followup to the SITA findings by the licensee identified two concerns involving the BWST level instrumentation and an emergency operating procedure (EOP) conflic BWST Level Instrumentation On February 12, 1998, engineering conducted evaluation and followup of the lack of a zero reference on the BWST drawing. Engineerin identified an error on the drawing that affected all of the level transmitters on each unit's BWST. The drawing showed the BWST level indicator taps to be approximately one foot below the value used in the EOP calculations. The condition of the as-found instrumentation coupled with then existing procedural guidance could have led to vortexing in the BWST prior to completion of BWST to RBES swapove Following an operability evaluation, operations declared the BWST level instrumentation inoperable on all three units, entered TS 3.0 for all three units, and initiated a one-hour non-emergency notification to the NRC. Maintenance personnel commenced calibrations of the level transmitters simultaneously on all three units. Each unit exited TS and entered TS 3.3.4 for instrumentation when the calibration of the first train of level instrumentation was completed. On February 13, 1998, maintenance completed the calibration of the second train of BWST level instrumentation for each unit and exited TS 3.3.4 at 2:30 a.m. for Unit 1, 3:09 a.m. for Unit 2, and 3:05 a.m. for Unit Licensee investigation identified that the BWST level instruments did not have a height difference calculation included in the instrument calibration from initial design. They replaced the level transmitters in 1989 to conform to Regulatory Guide 1.97 criteria. They did not identify the height difference during implementation of the modificatio II
- II_
EOP Conflict Engineering identified, on February 19, 1998. during a review.of the SITA findings, that the reactor building wide range level instruments have large uncertainties'. These uncertainties could create a conflict with EOP guidance for mitigation of loss of coolant accidents (LOCAs).
The guidance in the EOPs required the swapover of the suction for building spray (BS) and LPI pumps from the BWST to the RBES. To prevent air entrainment into the suction of the pumps, the RB water level must be greater than four feet and the BWST level must be greater than six feet. With the uncertainties in the RB level instrumentation, these conditions may not occur simultaneously, and therefore, due to a possible actual (lower) tank level this could cause air binding of the pump Following licensee review, operations management provided interim guidance to the operators to address the procedural deficiency and commenced revision of the EOP Engineering initiated a Failure Investigation Process (FIP) team to assess the root cause, corrective actions, and past operability of the systems. The licensee initiated a 10 CFR 50.72 notification to the NRC. The licensee issued a preliminary report on March 14, 1998, LER 50-269/98-0 RBES calculations for vortexing and debris transport were discussed in IR 50-269,270,287/97-14. Section E1.2. The licensee identified issue of trapping water in various areas inside the RB is discussed in IR 50 269.270,287/97-16, Section 01.3. As addressed in IR 50-269,270.287/97 18, the review and disposition of these items will remain open pending completion of the evaluations concerning the level instrumentation. The level instrumentation issue is identified as URI 50-269,270,287/98-02 10: Inaccurate BWST and RBES Instrumentatio c. Conclusions The inspectors identified an unresolved item on engineering review of as-built conditions for the reactor building emergency sump and the borated water storage tank level instrumentatio E3.2 10 CFR 50.46 Emergency Core Cooling System (ECCS) Reporting a. Inspection Scope The licensee discovered a problem with reporting required information in accordance with 10 CFR 50.46, Acceptance Criteria for Emergency Core Cooling for Light Water Nuclear Power Plants. The licensee entered the information into their corrective action system and the inspectors followed the licensee activities to their completio b. Observations and Findings As indicated in a Duke Power Company letter to the NRC, dated February 2, 1998, a 10 CFR 50.46 (a)(3) required report was not performed. The
II
letter, titled, Changes to or Errors in an ECCS Evaluation Model, indicated that annual changes in ECCS evaluation models (EM) or in the application of such a model that subsequently affected the peak cladding temperature calculations for 1995 made to the Oconee EM were not reported as required. The licensee subsequently documented the minor changes in the letter. They also documented this oversight in PIP report 0-098-208 on January 14. 1998, before the end of the next 10 CFR 50.46 reporting period. The licensee determined that one internal group failed to make the appropriate 1995 report in accordance with NSD 201, Reporting Requirements, Revision 7, Table A-2, that implements 10 CFR 50.46 requirement The licensee initiated the following corrective actions: the issuance of the aforementioned letter; counseling/re-training of the corporate office personnel involved: and the installation of an additional management review barrier to prevent such an oversight in the futur This non-repetitive, licensee identified and corrected violation is being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50-269,270,287/98-02-11:
Failure to Make Report Under 10 CFR 50.4 c. Conclusions The licensee failed to make a required 1995 10 CFR 50.46 report. This was identified as a non-cited violatio E3.3 Core Operating Limit Report (COLR) Errors a. Inspection Scope Site problem reports 1-098-0567 and 0-098-0635 documented the licensee's failure to detect an error introduced into the COLRs for all three Oconee units. Although the licensee stated that the errors did not create operational problems, it required a setpoint adjustment for the alert alarm on Unit 1 before 50 Effective Full Power Days (EFPD)
and past operability evaluations to be completed for Units 2 and 3. The inspectors followed the licensee's activities and the alteration of the Unit 1 alarm set point b. Observations and Findings On February 4, 1998, the licensee discovered that an error existed in the application of the energy deposition factor (EDF) on Unit 1 for the recently installed fuel (refueling 01C18) for operational power imbalance limits. The power-imbalance limits are based on comparison o the predicted allowable power distributions to vendor-provided Loss of Coolant Accident (LOCA) kilowatt/foot limits. The recently provided LOCA limits included corrections for the EDF. However, corporate design calculations also included application of the EDF to the predicted power distribution before comparison to the new LOCA limits. This double application resulted in slight non-conservative power-imbalance limits at mid-cycle for Unit 1. The error had been introduced into the COLR
addressed in TS 3.5.2.6 and in new setpoints for Unit Licensee calculations indicated that the stated Unit 1 condition was acceptable for continued power operation until 50 EFPD of operation into the cycle. Alarm set point changes were made before that time, at approximately 15 EFPD. The inspectors observed the technician's completion of the changes with an approved modification package, ON 0AC084, Power Tilt Monitor, Revision 0, with an accompanying 10 CFR 50.59 evaluation (Work Request 98005961). Operationa procedure changes were completed following the alarm setpoint change On February 10, 1998, the licensee determined that the same type of error had been made on Units 2 and 3. The same vendor and licensee double application of the EDF had been made. The PIP report of this discovery indicated that the.vendor had changed his practice in applying the EDF in all three instances. The most critical period where the power-imbalance alarm set points would have come into play had already occurred in the fuel cycles for both Units 2 and 3. -The licensee completed a worst-case evaluation of past potential impact had a accident occurred with the non-conservative set points installed. The evaluation concluded that there were no past operability problems because the alarms would-have provided protection as require CFR 50 Appendix B. Criterion III. Design Control, and the Duke Topical Report, state in part that design control measures shall provide for verifying or checking the adequacy of design by the performance of design reviews. Design control measures shall be applied to items such as reactor physics analysi NSD 306, Nuclear Fuel Reliability, Revision 5, which implements the above, assigns ownership for the fuel reliability program to the.
corporate office. Subsection 306.2.15 indicated that the corporate office was to evaluate fuel design changes and relevant.plant modifications for their impact on fuel reliability. Fuel design changes are evaluated in accordance with workplace procedure XSTP 101. Further, that office was to review fuel reload analyses and thermal limit calculations to ensure that these adequately assess expected fuel performance and incorporate operating histor Contrary to the above, during the review of the reload analyses the licensee missed the double application of the EDF. This is identified as VIO 50-269,270,287/98-02-12: Failure to Adequately Review Calculations in the COL c. Conclusions The licensee discovered that design errors had been introduced into reactor physics analysis for power-imbalance on all three Oconee unit This problem was documented as a design control violatio E8 Miscellaneous Engineering Issues (92903)
E8.1 (Open) Inspector Followup Item (IFI) 50-287/96-20-08: Integrated Control System (ICS) Post-Modification Testing (Open) IFI 50-287/97-01-04: Adequacy of Review Software Change The inspectors reviewed the procedures, attended the pre-job briefings, observed the testing, and reviewed the data for the following Unit 1 ICS tests: Main Feedwater Pump Trip from 70 percent reactor power, maximum runback from 65 percent to 50 percent reactor power, and reactor coolant pump trip from 50 percent powe The inspectors found the procedures adequately prepared to control the testing, collect data, deal with contingencies, and restore the unit to normal after testing. During the pre-job briefings the licensee gave a brief description of the testing, discussed the nuclear safety implications, discussed the roles and responsibilities of test and operations personnel, discussed management expectations for all participants, discussed contingencies, and gave opportunities for all participants to ask questions. The inspectors found the actual testing to be conducted.in a well-controlled manner with good evaluation of results. These items will remain open for further review following ICS testing on Unit E8.2 (Closed) LER 50-270/96-06 Revision 2:
Containment Isolation Valves Technically Inoperable During an inspection documented in NRC IR 50-269,270,287/95-25, the inspectors noted that the licensee's calculation for certain Anchor/Darling double disk gate valves had evaluated the thrust requirements for the flow cut-off condition. In that these valves included containment isolation functions, flow cut-off was considered an unacceptable condition. The licensee re-evaluated these items (Engineering Calculation OSC-6548) for hard seat contact with valve disk wedges in the preferred orientation and the non-referred orientatio The non-preferred orientation required greater closing thrus Calculation OSC 6548 was approved July 22, 1996 and was referenced in LER 50-270/96-06 and Supplement 1 dated February 27, 199 In a followup inspection of the licensee's GL 89-10 valve program in April 1997.( NRC IR 50-269.270,287/97-05) the inspectors reviewed the licensee's actions regarding Anchor/Darling double disk gate valve During this review the inspectors noted that the calculation using the Electric Power Research Institute (EPRI) model had not accounted for instrument error and other uncertainties (diagnostic equipment uncertainty, torque switch repeatabilit and load sensitive behavior).
The licensee developed re-evaluations which demonstrated the operability of the valves. However these re-evaluations conflicted with the evaluations referred to in LER 50-270/96-06. The licensee stated that a revised LER would be issue During the current inspection, the inspectors reviewed the revised LER 50-270/96-06, Revision 2, dated July 16, 1997. and concluded the revised version was acceptable. Revision 2 contained the root cause, corrective actions which were taken, and safety evaluation. The inspectors verified completion of the corrective actions. Calculation OSC 6548 was deleted and updated Calculations OSC 5674, Revision 5. OSC 5675, Revision 3, and OSC 5599, Revision 3, for respective Units 1, 2. and 3 contain the EPRI Performance Prediction Method calculations including uncertaintie E8.3 (Closed) VIO 50-269,270,287/97-05-06: Operability Calculation Failed to Account for Instrument Error and Other Uncertainties Engineering Calculation OSC 6548 was performed to verify the ability of Anchor/Darling double disk gate valves to achieve hard seat contac The calculation was approved July 22, 1996, and indicated that all of these valves were operable for the preferred valve orientation (i.e. the lower wedges installed toward the downstream side). The non-preferred orientation required greater thrust. During subsequent inspection of the valves, four valves were installed in the non-preferred directio The disk wedges were reversed and the valves considered operable at hard seat contact in the preferred orientatio During a followup inspection of the licensee's GL 89-10 program, the inspectors reviewed the licensee activities related to the Anchor/Darling valves.. The inspectors found that Calculation OSC 6548 had not correctly compared the thrust requirements of the valves to the as-measured thrusts available at torque switch trip. The calculation was deficient in that it failed to account for instrument error and other uncertainties (diagnostic equipment uncertainty, torque switch repeatability, and load sensitive behavior). In that Calculation OSC 6548 did not include instrument error and other uncertainties in the EPRI Performance Prediction Methodology calculations, it did not assure that inoperability would be promptly identified and correcte Consequently a violation against 10 CFR 50, Appendix B, Criterion XVI (Corrective Action) was identifie In a letter dated August 18, 1997, from W. R. McCollum, Jr. to the NRC the licensee provided a response to the violation. The inspectors confirmed that the licensee had incorporated instrument error and other uncertainties into the EPRI Performance Prediction Program calculations in the following revised design base calculations: OSC 5674, Revision 5 (Unit 1, 5/1/97): OSC 5675, Revision 3 (Unit 2, 5/6/97); and OSC 5599, Revision 3 (Unit 3, 5/16/97).
The inspectors also determined that plant and general office personnel were aware of NRC expectations concerning the NRC Safety Evaluation and Supplemental Safety Evaluation of the EPRI MOV Performance Prediction Program. Duke has incorporated the NRC safety evaluations into Revision 6 of DPS 1205.19-00-0002, "Guideline for Performing Motor Operated Valve Reviews and Calculations," as Attachment 2 E8.4 Generic Letter 89-10 Program Weaknesses a. Inspection Scope During an inspection in April 1997, (NRC IR 50-269.270.287/97-05), the inspectors identified two conditions that were considered weaknesses in the licensee's Generic Letter 89-10 program. The inspectors reviewed these conditions and determined that the licensee had taken actions to strengthen the progra b. Observation and Findings During review of the setup calculation for a newly installed valve, the inspectors found that approval and independent verification.of the calculation were not required to be documente The licensee had revised the process of issuing test acceptance criteria (TAC) sheets to the field for valve setup. TAC sheets are issued as modifications requiring independent review and approval of the valve setup calculatio While the licensee had used the EPRI Performance-Prediction Methodology on establishing certain valve settings, they had not documented consideration of the NRC Safety Evaluation and Supplement Evaluation of the EPRI Performance Prediction Progra The inspectors found that the licensee had incorporated the NRC Safety Evaluations into Revision 6 of DPS 1205.19-00-0002."Guideline for Performing Motor Operated Valve Reviews and Calculations."
c. Conclusions The inspectors concluded that the'licensee had.taken adequate action to address the NRC concern I Plant Support Areas R1 Radiological Protection and Chemistry Controls R1.1 Tour of Radiological Protected Areas a. Inspection Scope (84750)
The inspectors reviewed implementation of selected elements of the licensee's radi-ation protection program as required by 10 CFR Parts 20.1902, and 1904. The review included observation of radiological protection activities for control of radioactive material, including postings and labeling, and radioactive waste processin b. Observations and Findings At the time of the inspection, Units 1, 2, and 3 were at.100 percent power. The inspectors reviewed survey data of radioactive material
- 30 storage areas. Observations and independent radiation and contamination survey results determined the licensee was effectively controlling and storing radioactive material and all material observed was appropriately labeled as required by 10 CFR Part 20.1904. All areas observed were appropriately posted to specify the radiological conditions. The inspectors determined the licensee was processing radioactive waste to maintain exposures As Low As Reasonably Achievable (ALARA) and to minimize quantities of radioactive waste stored on sit The inspectors also reviewed and discussed radioactive Tfqufd processing during tours of the radioactive waste (Radwaste) facility and observed preparations for a radioactive liquid discharg c. Conclusions Based on observations and procedural reviews, the inspectors determined the licensee was effectively maintaining controls for radioactive material storage and radioactive waste processin R1.2 Water Chemistry Controls a. Inspection Scope (84750)
The inspectors reviewed implementation of selected elements of the licensee's water chemistry control program for monitoring primary and secondary water quality as described in the TS limits, the Station Chemistry Manual, and the UFSAR. The review included examination of program guidance and implementing procedures and analytical results for selected chemistry parameter b. Observations and Findings The inspectors reviewed selected analytical results recorded for Units 1, 2. and 3 reactor coolant taken between November 26, 1997, and February 10, 1998, and secondary samples taken between November 1, 199 and February 1, 1998. The selected parameters reviewed for primary chemistry included dissolved oxygen, chloride, pH, and fluoride. The selected parameters reviewed for secondary chemistry included hydrazine, iron, and chloride. Those primary parameters reviewed were maintained well within the relevant TS limits for power operations. Those secondary parameters reviewed were maintained according to station procedures. During tours, the inspectors also observed the licensee performing sampling for hydrogen in waste gas tank 1-B. The inspectors verified the sample was performed as required by licensee chemistry sampling procedure CP/0/B2002/1 c. Conclusions Based on the above reviews, it was concluded that the licensee's water chemistry control program for monitoring primary and secondary water quality had been effectively implemented, for those parameters reviewed, in accordance with the TS requirements and the Station Chemistry Manual for water chemistr R1.3 Transportation of Radioactive Materials a. Inspection Scope (86750)
The inspectors evaluated the licensee's transportation of radioactive material's programs for implementing the revised Department of Transportation (DOT) and NRC transportation regulations for shipment of radioactive materials as required by 10 CFR 71.5 and 49 CFR Parts 100 through 17 b. Observations and Findings The inspectors reviewed and discussed licensee procedures and determined that they adequately addressed the following: assuring that the receiver has a license to receive the material being shipped; assigning the form, quantity type, and proper shipping name of the material to be shipped; classifying waste destined for burial; selecting the type of package required; assuring that the radiation and contamination limits are met; and preparing shipping paper The inspectors observed preparations for a shipment of radioactive waste to a processor for volume reduction and determined the shipment was prepared following the requirements of 10 CFR 71.5 and 49 CFR Parts 100 through 17 c. Conclusions Based on the above reviews, the inspectors determined that the licensee had continued to effectively implement a program for shipping radioactive material R2 Status of Radiation Protection (RP) Facilities and Equipment R2.1 Environmental Monitoring and Effluent Equipment a. Inspection Scope (84750)
The inspection scope was to determine if process and effluent radiation monitors and radiological environmental monitors were being maintained in an operational condition. TS 6.4.4.f required the licensee establish, implement, and maintain a program to monitor the radiation and radionuclides in the environs of the plant as described in Chapter 16 of the UFSA b. Observations and Findings During tours of the auxiliary building and radwaste building, the inspectors observed process radiation effluent monitors in service. The inspectors observed the Unit 2 vent radiation indicating alarm (RIA)
monitor inlet sample tubing for RIA 43 and 44 did not appear to have the correct bend radius in two locations as specified on licensee design drawing number 0-440, Piping Layout Plan. The note on the drawing
- 32 specified the bend radius of the tubing to be five diameter bend or greate The inspector's concern was bend radius can effect deposition of radioactive particulate and iodine material in the tubing and potentially result in an inaccurate monitor reading. The licensee initiated action to investigate the sample tubing bend radius as compared to the design drawing. The inspectors requested additional information regarding the licensee's evaluations of the monitor sample tubing bend radius. Pending review of this information this is identified as URI 50-270/98-02-13: Unit 2 Monitor Inlet Sample Tubing Bend Radius Not as Described by Design Drawing The inspectors observed environmental samplers at two air sampling stations and two liquid sampling stations and discussed sampling and counting procedures with laboratory personnel. The inspectors determined that the sampling equipment was calibrated and functional at the time of inspection. The inspectors also verified locations were consistent with their descriptions in the UFSAR and that the samples performed were in accordance with procedures CP/O/B/2005/11, Airborne Radioiodine and Particulate Sampling and CP/O/B/2005/12. Liquid Sampling. The licensee did not identify any sampling deviations in 1997 because of equipment malfunction Conclusions The inspectors concluded effluent and environmental monitors were being maintained in an operational condition to comply with TS requirements and UFSAR commitment However, one URI was identified to determine if a Unit 2 monitor sample tubing was as described on a design drawin R2.2 Meteorological Monitoring Equipment a. Inspection Scope (84750)
Section 2.3.3.2 of the UFSAR described the operational and surveillance requirements for the meteorological monitoring instrumentatio b. Observations and Findings The inspectors toured the control room with cognizant licensee personnel and determined that the meteorological instrumentation was operable and that data for wind speed, wind direction, air temperature, and precipitation were being collected as described in the UFSAR. Review of records determined the ]icensee had maintained a high level of operability for meteorology equipment during 1997. Wind speed and wind direction instruments at ten and sixty meters were operable approximately 99.5 percent, air temperature was approximately 9 percent and precipitation 99.7 percen *
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c. Conclusions Based on the above reviews and observations, it was concluded that the meteorological instrumentation had been adequately maintained and that the meteorological monitoring program had been effectively implemente R5 Staff Training and Qualification in Radiation Protection and Chemistry a. Inspection Scope (84750)
Training of RP technicians was reviewed to determined whether the technicians had been provided adequate training in procedures to minimize radiation exposures and control radioactive material as required by 10 CFR Part 19.1 b. Observations and Findings The inspectors reviewed training records for personnel involved with performing environmental and effluent surveys to control radioactive material and determined personnel had received training and were maintaining training qua ifications for the assigned tas.c. Conclusions The inspectors concluded that personnel involved with performing environmental and effluent surveys were maintaining current training qualification V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 26, 1998. The licensee acknowledged the findings presented. No proprietary information was identified to the inspectors. The inspectors informed the licensee that material condition and housekeeping practices in the two rooms inspected, gave the appearance of neglect by area owners and job sponsors who were responsible for ensuring that applicable requirements were being enforce Partial List of Persons Contacted Licensee E. Burchfield. Regulatory Compliance Manager T. Coutu, Scheduling Manager D. Coyle, Mechanical Systems Engineering Manager T. Curtis. Operations Superintendent B. Dobson, Mechanical/Civil Engineering Manager W. Foster, Safety Assurance Manager D. Hubbard, Maintenance Superintendent C. Little. Electrical Systems/Equipment Engineering Manager W. McCollum, Vice President, Oconee Site M. Nazar. Manager of Engineering J. Forbes. Station Manager J. Smith, Regulatory Compliance J. Twiggs, Manager. Radiation Protection Other licensee employees contacted during the inspection included technician maintenance personnel, and administrative personne NRC LaBarge, Project Manager Inspection Procedures Used IP37550 Engineering IP37551 Onsite Engineering IP61726 Surveillance Observations IP62700 Maintenance Program Implementation IP62707 Maintenance Observations IP71707 Plant Operations IP71750 Plant Support Activities IP73753 Inservice Inspection IP84750 Radioactive Waste Treatment and Effluent and Environmental IP86750 Solid Rad Waste Management and Transportation of Radioactive Material '
IP90712 In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP92901 Followup - Plant Operations EP92903 Follon
- Engineering IP93702 Prompt nsite Response to Events
- 35 Items Opened, Closed, and Discussed Opened 50-269,270,287/98-02-01 NCV Failure to Follow Procedure-Three Examples(Section 04.1)
50-269/98-02-02 NCV Inadequate Review of Removal and Restoration Book-Two Examples (Section 04.2)
50-270/98-02-03 VIO Failure to Implement Temporary Modification In a Timely Fashion (Section M1.2)
50-269,270/98-02-04 VIC Failure to Follow Procedure for Foreign Material Control (Section M2.1)
50-269/98-02-05 VID Failure to Follow Modification Procedure (Section M2.2)
50-269/98-02-06 URI Improperly Installed Valve Packing Gland Fasteners (Section M2.2)
50-270/98-02-07 VIO Failure to Impement Procedural Requirements Relative to Material Condition and Housekeeping Practices-Two Examples (Section M2.3)
50-287/98-02-08 NCV Failure to Follow Calibration Procedure (Section M4.1)
50-269/98-02-09 URI Failure of Valve 1 HP-27 to Close (Section E1.1)
50-269,270,287/98-02-10 URI Inaccurate BWST and RBES Instrumentation (Section E3.1)
50-269,270,287/98-02-11 NCV Failure to Make Report Under 10 CFR 50.46 (Section E3.2)
50-269,270,287/98-02-12 VIC Failure to Adequately Review Calculations in the COLR (Section E3.3)
50-270/98-02-13 URI Unit 2 Monitor Inlet Sample Tubing Bend Radius Not as Described by, Design Drawing (Section R2.1)
Closed 50-269,270,287/97-18-03 URI SSF Diesel Generator Operation (Section 08. 1)
50-/96-06 (Revision 02)
LER Containment Isolation Valves Technically Inoperable (Section E8.2)
50-269,270,287/97-05-06 VIO Operability Calculation Failed to Account for Instrumentation Error and Other Uncertainties (Section E8.3)
Discussed 50-269,270,287/98-01-01 IFI NSRB Reviewof 10 CFR'50 *59 Safety Evaluation (Section 08.2)
50-287/96-20-08 IFI ICS Post Modification Testing (Section E8. 1)
50-287/97-01-04 IFI Adequacy of Review Software Change (Section E8.1)
List of Acronyms ALARA As Low As Reasonably Achievable ANSI American National Standard ASME American Society of Mechanical Engineers BS Building S iay BTO Block Tag Out BWST Borated Water Storage Tank CBAST Concentrated Boric Acid Tank cc Component Cooling CFR Code of Federal Regulations COLR Core Operating Limits Report CRD Control Rod Drive DOT Department of Transportation ECCS Emergency Core Cooling System EDF Energy Deposition Factor EFPD Effective Full Power Days EOC End of Cycle EPRI Electric Power Research Institute EM Evaluation Model EOP Emergency Operating Procedur ES Engineered Safeguards F
Fahrenheit FIP Failure Investigation *Process FME Foreign Material Exclusion GL Generic Letter HPI High Pressure Injection ICS Integrated Control System IFI Inspector Report IR Inspection Repor ISI Inservice inspection LER Licensee Event Report LCO Limiting Condition for Operation LOCA Loss of Coolant Accident LPI Low Pressure Injection
LPSW Low Pressure Service Water MDEFW Motor Driven Emergency Feedwater MOV MotoriOprated Valve MSDS Materia Safety Data Sheet NCV Non-Cited Violation NLO Non-Licensed Operator NRC Nuclear Regulatory Commission NSRB Nuclear Safety Review Board NSD Nuclear System Directive OTSG Once Through Steam Generator PDR Public Document Room PIP Problem Investigation Process PSIG Pounds Per Square Inch Gauge PSL Pressurizer Surge Line PT Penetrant Test QA Quality Assurance Radwaste Radioactive Waste RB Reactor Building RBES Reactor Building Emergency Sump RCS Reactor Coolant System REV Revision RFO Refueling Outage RIA Radiation Indicating Alarm RP Radiation Protection R&R Removal & Restoration SFP Spent Fuel Pool SGI Safeguards Information SITA Self-Initiated Technical Audit SRO Senior Reactor Operator SSF Safe Shutdown Facility TAC Test Acceptance Criteria TDEFW Turbin6,Driven Emergency Feedwater Pump TM Temporary Modification T&QP Training and Qualification Program TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved Item USQ Unreviewed Safety Question UT Ultrasonic Test VIO Violation WMS Work Management System WO Work Order