IR 05000413/1998011
| ML20199J879 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 01/11/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20199J857 | List: |
| References | |
| 50-413-98-11, 50-414-98-11, NUDOCS 9901260269 | |
| Download: ML20199J879 (21) | |
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U.S. NUCLEAR REGULATORY COMMISSION -- -
REGION 11 !
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Docket Nos: 50-413,50-414 :
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License Nos: NPF-35, NPF-52 Report Nos.: 50-413/98-11,50-414/98-11 )
l Licensee: Duke Energy Corporation l
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Facility: Catawba Nuclear Station, Units 1 and 2 l
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Location: 422 South Church Street Charlotte, NC 28242 Dates: November 1 - December 12,1998 l
Inspectors: D. Roberts, Senior Resident inspector R. Franovich, Resident inspector M. Giles, Resident inspector F. Jape, Senior Project Manager (Sections 08.2,08.3, M8.2, E8.1. E8.2)
C. Payne, Senior License Examiner (Sections OS,08.4)
E. Testa Senior Radiation Specialist (Section R2)
. Approved by: C. Ogle, Chief Reactor Projects Branch 1 Division of Reactor Projects i
Enclosure
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9901260269 990111 PDR ADOCK 05000413 G <
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EXECUTIVE SUMMARY Catawba Nuclear Station, Units 1 and 2 NRC Inspection Report 50-413/98-11,50-414/98-11
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This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspections, as well as the
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results of announced inspections by three regional based inspectors. [ Applicable template i
codes and the assessment for items inspected are provided below.).
Operations l
- I An ongoing problem with cold leg accumulator leakage due to safety injection system check valves not properly seating represented an operational challenge between !
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October 31 and November 3,1998. The decision by operators to perform sections of a l procedure associated with reseating check valves for all four cold leg accumulators
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l contributed to the problem. (Section 01.2; [NEG: 1 A, 2A))
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Control room operators performed well during elevated cold leg accumulator leakage
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between October 31 and November 3,1998, ensuring that Technical Specification limits l were not exceeded, that the plant remained stable, and that management was kept informed of developments as they occurred. (Section 01.2;[POS: 1A)) ;
The licensee identified the need for a long-term solution to the cold leg accumulator check valves repeatedly becoming unseated following small perturbations in safety injection system pressure. (Section 01.2;[POS: SA))
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A weakness was identified in the licensee's freeze protection program in that the Chemistry Department was not performing actions as required in program document The licensee appropriately resolved this, along with other related inspector-identified
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discrepancies, during the inspection period. (Section O2.1; [ WEAK: 28))
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The freeze protection coordinator demonstrated a thorough knowledge of the program
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adequate to ensure the cold weather program requirements were satisfied. (Section O2.1; [POS: 3B,4B])
Control room operations were being conducted professionally, safely, and consistent I
with plant administrative and operating procedures. (Section 05.1; [POS: 1 A, 3A))
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{- The conduct and performance of the simulator examinations were satisfactory. The evaluators were thorough in noting individual performance discrepancies and the scenarios observed were effective in discriminating incompetent from competent operators. Documentation of individual performance results was satisfactory. The written examination was an excellent tool for distinguishing between competent, qualified
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A non-cited violation was identified concerning a 1997 non-compliance with Technical l
Specification 3.7.3 in which the 2A1 component cooling water pump was inoperable for three weeks. (Section 08.1; [NCV: SA, SC NEG: 2A))
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Maintenance
A non-cited violation war. identified concerning a 1998 non-compliance with Technical l Specification 4.7.13.6 due to the omission of required surveillance testing of standby j
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shutdown system incere thermocouple reference junction box resistance temperature i detectors. (Section M8.1;[NCV: SA, SC; NEG: 28]) 1
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Plant Support '
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.. Radiation and process effluent monitors and environmental monitors were being maintained in an operational conditioni in compliance with Technical Specification requirements and Updated Final Safety Analysis Report commitments. (Section R2.1; i
[POS: 1C)) ;
-. 1 Offsite doses from site radioactive effluents were small percentages of the annual dose limits of 40 CFR 190.10(a). (Section R2.1;[POS: 1C))- '
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A program for shipping and receiving of radioactive materials had been implemented as required by NRC and Department of Transportation regulations. (Section R2.2; [POS: 1C))
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l Reoort Details i
Summary of Plant Status I
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l Unit 1 operated at or near 100 percent reactor power for the duration of the inspection perio Unit 2 operated at.100 percent power until November 5,1998, when a power reduction to 97 percent was conducted to allow inspection and testing of the 2A steam generator power ;
operated relief valve,2SV-19, which had been repaired earlier that day for seat leakage. Power :
was returned to 100 percent on November 6,1998, where it remained until November 8,1998, when a reduction to 55 percent reactor power was initiated to repair the 2A main feedwater pump turbine mechanical overspeed trip mechanism. A trip piston was replaced on November i 9,1998, and a reactor power increase was in'itiated on November 11,1998, following successful i i
' post-maintenance testing. The unit reached 100 percent power operation later that day and l operated there for the remainder of the inspection perio )
1. Operations l 01 Conduct of Operations
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O1.1 General Comments (71707)
The inspectors conducted frequent control room tours to verify proper staffing, operator 1 attentiveness and communications, and adherence to approved procedures. The l inspectors attended operations shift turnovers and site direction meetings to maintain
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' awareness of overall plant status and operations. Operator logs were reviewed to verify operational safety and compliance with Technical Specifications (TS). Instrumentation, computer indications, and safety system lineups were periodically reviewed, along with equipment removal and restoration tagouts, to assess system availability. The TS Action item Log (TSAIL) books for both units were reviewed daily for potential entries into limiting conditions for operation (LCO) action statements. The inspectors conducted plant tours to observe material condition and housekeeping. Problem Identification Process (PIP) reports were routinely reviewed to ensure that potential safety concerns and equipment problems were resolved. No violations, deviations, or major concerns were identified in these area .2 Cold Lea Accumulator Leakaae Due To Check Valves Not Properly Seated Inspection Scone (71707)
The inspectors reviewed the licensee's activities to address a continuing problem with cold leg accumulator (CLA) leakage that was exacerbated on October 31,1998, after operators performed a procedure to reseat check valves in the safety injection syste Cold leg accumulator leakage issues have been' discussed in NRC Inspection Reports 50-413,414/98-07 and 98-0 i Observations and Findinas '
On October 31,1998, after operators performed procedure OP/2/A/6200/006, Safety injection System, Revision 38, Enclosure 4.8, " Reseating Cold Leg injection Check i
Valves," to reseat check valves associated with the 2B CLA, all four Unit 2 CLAs l
experienced either inteakage or outleakage when check valves between them and the f
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residual heat removal (ND) and safety injection (NI) systems did not reseat properl Three of the four CLAs (2A,2C, and 2D) were simultaneously leaking into the ND system causing its pressure to reach approximately 600 pounds per square inch gauge within a few hours and requiring operators to vent the system two to three times per shift over the next three days. -Cold leg accumulator 28 was experiencing inleakage, and had been since before the procedure was performed on October 31,1998, requiring operators to drain it periodically. . Operators performed sections of Enclosure associated with all four CLAs, although only CLA 2B had leakage problems at the tim Apparently, performing the procedure on all four CLAs disturbed the valve seating integrity for the three previously unaffected CLAs. Site management and engineering management were unable to explain to the inspectors the basis for the decision to perform this procedure on the three unaffected CLA The licensee chartered a Failure Investigation Process (FIP) team to troubleshoot the leakage problem and recommend corrective actions. On November 3,1998, with concurrence from site engineering and management, operators performed procedure Enclosure 4.5, "NI Pump 2A Recirculation," to reseat the check valves. This enclosure, which closed the check valves by essentially placing Ni pump discharge pressure directly on them, stabilized ND system pressures resulting in the need for only periodic venting (less than once a week) through the end of the inspection period. Enclosure of the procedure was temporarily placed on administrative hold by the licensee pending engineering review of the procedure for adequac The inspectors observed operators venting the ND system, observed control room activities, reviewed logs, interviewed plant personnel, and observed FIP team activitie The inspectors concluded that the elevated leakage following the October 31,1998, reseating evolution, posed an increased burden to control room and plant staf Operators had to frequently monitor the changes in CLA levels and made numerous additional control room log entries. Frequent monitoring of ND system pressure was required locally at the ND pump rooms. The changes in CLA levels required numerous Ni pump starts for filling the CLAs, along with sampling to determine if TS-required boron concentration levels were maintained. Also, the frequent venting of the ND system subjected operators to additional radiation exposur The inspectors did note that the operators effectively accommodated this increased burden. For example, new CLA sample results were documented when required and boron concentrations, based on log entries, were within limits. Operators effectively maintained CLA levels within TS limits. No gas or air was observed issuing from the ND system high point vent by the inspectors. The inspectors also reviewed drawings and verified that the leakage into the ND system was from the CLAs and not the reactor coolant system. Leakage from reactor coolant system pressure boundary valves was still within TS limit Although the CLA leak rates were significantly reduced after procedure Enclosure was performed, the underlying root cause and corrective actions to prevent recurrence had not been developed by the end of the inspection period. Engineering and maintenance personnel were tasked by licensee management to research a long-term solution and focus on potential modifications or adjustments to the check valves that would allow them to seat properly under nominal differential pressures. Corrective actions are documented in PIP 2-C98-4223 to address this. In the interim, the FIP team
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i recommended continued monitoring and performance of the ND venting procedure and procedure OP/2/A/6200/006, Enclosure 4.5, if the problem recurre The licensee determined that minor enhancements to Enclosure 4.8 were necessary !
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The inspectors concluded that the operators' decision on October 31,1998, to perform i sections of procedure Enclosure 4.8 associated with all four CLAs, when only CLA B was >
experiencing inleakage, contributed to the problem. The subsequent problem with elevated cold leg accumulator leakage due to safety injection system check valves not !
properly seating represented an operational challenge between October 31 and November 3,1998. Operations decision to perform sections of a procedure associated !
with reseating check valves for all four cold leg accumulators contributed to the proble :
Control room operators performed well during the challenge, ensuring that TS limits were '
not exceeded, that the plant remained stable, and that management was kept informed ,
of developments as they occurred. The licensee has identified the need for a long-term i solution to the check valves repeatedly becoming unseated following small perturbations in NI system pressur .3 Onsite Followuo of Events - General Comrnents (93702. 71707)
Plant Outside Desian Basis Due to an Uninstalled Interlock Associated with Containment Sorav and Residual Heat Removal Pumos' Sumo Pumos
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On October 20,1998, during a design review associated with a proposed station I
modification, the licensee identified an issue involving an interlock that had not been installed in either unit's containment spray (NS) and ND pumps' sump pump control circuitry. The installation of the interlock was a licensee commitment made to the NRC
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for both units while the plant war, being licensed. The interlock's design function would have been to trip the sump pumps on a safety injection signal and allow them to restart l on a high-high sump level. This restart would be accompanied by a control room alarm,
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thereby providing control room operators indication of any emergency core cooling system (ECCS) leakage following a loss of coolant accident. The licensee took immediate corrective action to place the sump pumps in * standby mode, which defeated normal pump operation on a high sump level but would allow pump start and concurrent l
alarms on a high-high sump level, consistent with the licensing basis. The inspectors verified that the sump pumps were operating in standby mod The licensee submitted Licensee Event Report (LER) 50-413/98-16 on November 19, 1998, to notify the NRC of this condition outside design basis. The inspectors determined that the licensee met reportability requirements delineated in 10 CFR 50.72 and 50.73. Further NRC review for determining regulatory and safety significance will be performed during review of this LE _
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O2 Operational Status of Facilities and Equipment O2.1 Cold Weather Protection Preparations a.- Inspection Scope (71714) -- - -
. The inspectors reviewed Nuclear. System Directive (NSD) 317, Freeze Protection Program, Revision 1, Chemistry Guideline 3.4.31, Chemistry Freeze Protection Plan, various station procedures, completed work orders, and related PIPS. The inspectors also interviewed the freeze protection coordinator, performed plant tours, and observed the performance of annual preventative maintenance to verify the adequacy of instailed freeze protection equipmen Observations and Findinas Nuclear System Directive (NSD) 317, Freeze Protection Program, Revision 1, was implemented at Catawba to ensure reliability and operability of systems and components when subjected to freezing conditions. The NSD outlined the station departments required to participate in implementing the freeze protection program, as well as their individual responsibilities. The inspectors identified a requirement of the chemistry department, which was to implement Chemistry Guideline 3.4.31, Chemistry Freeze Protection Plan, anytime the outside temperature dropped to 32 degrees Fahrenheit and/or notification had been received from the operations department that procedure PT/0/B/4700/038, Revision 009, Cold Weather Protection, was active. This requirement was not being implemented. The guideline specified that the chemistry department should monitor the chemistry controlled areas and systems until notified and/or the outside temperature was greater than 32 degrees Fahrenheit, and that all areas of chemistry shall develop procedures to periodically verify proper operation of freeze protection systems and equipment during the cold weather season that was not covered by model work orders. Tne licensee did not have procedures that fulfilled these i
requirements and generated PIP 0-C98-4457 to document this discrepancy. The l chemistry department subsequently developed and implemented rounds sheets to fulfill the requirements of Chemistry Guideline 3.4.31 and NSD 317. Although not a regulatory l requirement, the inspectors considered the failure of the chemistry department to implement Chemistry Guideline 3.4.31 to be a weakness in the freeze protection program. The inspectors verified that the previous failure to properly implement this guideline had minimal potentialimpact on safety-related plant equipment function The inspectors reviewed procedure IP/0/B/3560/008, Revision 005, Preventative Maintenance and Operational Check of Freeze Protection Heat Trace and Instrument Box Heater (EHT/ElB) Systems. This procedure performed annual and monthly checkouts of the electric heat trace system circuits, insulation, and internal enclosures
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l heaters. Procedural provisions were also included to perform Enclosure 11.4, Extreme Cold Weather Checklist, wb:en outside temperatures in the mid-teens were expected, or
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when prolonged subfreezing temperatures were expected. This checklist verified that
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properl The inspectors noted that there was no forma'ized method to initiate the extreme cold weather checklist and that it was currently being implemented at the discretion of the freeze protection coordinator, in view of the inspectors' concern that no assurance
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existed that the procedure would be performed in his absence, the freeze protection
coordinator initiated actions to have Operator Aid Computer point C2P0118, which monitored the outside ambient temperature, modified to include an alarm setpoint at 22 degrees Fahrenheit with specific instructions to initiate the extreme cold wea'.her
- checklist. The inspectors did not identify any instances in which the extreme cold , i weather checklist was not performed when require ;
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'The insp'ectors performeEmul'iple t plant tours to assess n[aterial condition and verify proper operating status of freeze protection equipment. Minor discrepancies identified !
by the inspectors were communicated to the freeze protection coordinator who indicated i that corrective work orders would be generated. The inspectors verified proper thermostat settings. The inspectors also observed performance of the annual checkout of the Unit 1 and Unit 2 refueling water storage tank level transmitter instrument box :
heaters per IP/0/B/3560/008. Work was performed in accordance with the approved i procedur '
The inspectors reviewed selected model work orders listed on the Winter Update On Cold Weather Protection report, which was distributed periodically at the daily site !
direction meeting to provide status on outstanding items necessary for completion of the l cold weather protection program. The freeze protection coordinator was knowledgeable l of material condition issues or discrepancies documented in the specific work order '
The licensee completed implementation of the cold weather program model work orders by November 21,199 ,
q The freeze protection coordinator also maintained a list of all outstanding work items coded to freeze protection equipment, which were prioritized based on risk potential to systems / components that required freeze protection measure l c, Conclusions I The inspectors identified a weakness in the licensee's freeze protection program, in that the Chemistry Department was not performing actions as required in program documents. The licensee appropriately resolved this, along with other related inspector-identified discrepancies, during the inspection period. The freeze protection coordinator {
i demonstrated a thorough knowledge of the program and of ongoing related maintenance activities. The licensee's existing activities, coupled with actions to address minor ~ !
deficiencies identified during the inspection, were adequate to ensure the cold weather program requirements were satisfie Licensed Operator Requalification Program Evaluation The inspector conducted a routine, announced inspection of the licensed operator requalification program during the period December 1-4,1998. Specific areas of review included control room (CR) activities, requalification simulator training, biennial written and annual operating requalification examinations, and compliance with training department procedure .
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05.1 Control Room Observation Lnspection Scope (71001) i i
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-The inspector observed licensed operator activities in the CR over portions of two
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i separate shifts. Operator performance was measured against the licensee's !
. administrative procedures, conduct of operations, and compliance with T ~ b; Observations and Findinos The inspector monitored the activities'of operating crews "C" and "E" during routine ;
control room operation and post-maintenance testing. The inspector observed that CR ;
activities were performed in a formal and professional manner. The Senior Reactor '
Operator (SRO) properly controlled access to the CR to minimize disruptions and i distractions. The reactor operators (ROs) were generally attentive to their panels, .
promptly responded to CR alarms, properly referenced plant procedures and l communicated in a clear, concise manner in accordance with the site communications I standard, i The post-maintenance testing activities involved replacement of a defective meter on the instrument drawer for power range nuclear instrument N-41 and repair of a leaking sight l glass in the lubrication oil system of diesel generator 1A. The inspector observed that '
these activities were well controlled by the control room operators and communications '
between the field operators, field technicians and the CR were good. The inspector particularly noted that the field operators and technicians were attentive to ensuring the l CR operators were informed prior to receiving an alarm in the CR caused by their '
testin l Conclusions The inspector concluded that CR operations were being conducted professionally, i safely, and consistent with plant administrative and operating procedure ,
05.2 Annual Operatino and Biennial Written Examinations Insoection Scope (71001)
L The inspector observed the licensee's conduct of the annual operating test to three teams of licensed operators from operating crew"B." The test consisted of two simulator scenarios and five job performance measures (JPMs). The inspector also reviewed the written examination administered to this crew for content and quality. The inspection
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! requalification training in accordance with 10 CFR 55.59, "Requalification." Observations and Findinos l The inspector observed the administration of two active simulator examination scenarios
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guides listing expected operator actions hcked some detail. However, through use of
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various simulated equipment malfunctions, the operators were required to perform significant actions that demonstrated their skill and ability to operate the plant. The inspector observed that the facility evaluators graded the operators' performance per the exercise guide, as well as per other criteria consistent with facility procedures and
- management expectations not specifically listed in the guide During the plant walkthrough portion of the operating test, the inspector noted that one JPM performed in the auxiliary building had a low level of difficulty and did not afford the evaluator a measure of operator competence. The JPM required the operator to find a ladder and then locate and manipulate three system valves. The inspector judged this JPM to be a poor measure of a licensed operators' skill and abilit Regardless of the above, the inspector found that both scenarios and four of five JPMs were challenging and discriminating test tools that were appropriate for measuring the knowledge and skill of the operators. The inspector observed the facility evaluator debrief sessions and reviewed the evaluator documentation of the operator's performance. The evaluators comments and findings were appropriate and agreed with NRC observation The inspector reviewed the written examination for content and quality. The inspector noted that the licensee had developed both an RO and SRO version of the examinatio The inspector applied the guidance of Appendix A from NRC inspection procedure 71001 in evaluating the quality and content of the examination. The inspector found that '
the questions were operationally oriented and, in general, tested requalification training material at the comprehension or analysis level. The test's level of difficulty challenged the operator's knowledge and understanding of the system concepts and procedural requirements. The inspector noted that the quality of the reviewed questions were comparable to those used during initial licensing of new operators by the NR Conclusions i The inspector determined that the conduct and performance of the annual operating l tests were satisfactory. The facility evaluators adequately noted individual operator l performance discrepancies and the examination test items, in general, were judged to be good evaluation tools. Documentation of individual performance results was satisfactor The inspector also determined that the biennial written examination was an excellent tool for distinguishing between competent, qualified operators and those needing additional l
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training and remediation. The inspector concluded that this portion of the licensed 1 operator requalification program met the requirements of 10 CFR 55.59, I
- Requalification."
08 Miscellaneous Operations issues (90712,92901)
08.1 (Closed) Licensee Event Report (LER) 50-414/97-003: Component Cooling System Unavailability This LER described an event in which engineering determined that between January 25, 1997, and February 17,1997, the 2A1 component cooling water (KC) pump would not l have restarted automatically during an event following a load shed. Licensee documentation indicated that the pump motor breaker would not close on demand because the closing springs were not fully charged. The root cause of this event was the l l
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f failure of the breaker charging spring motor on January 25,1997. Documentation i
revealed that the licensee had three prior opportunities to identify the inoperable :
condition, during weekly electrical power source alignment checks per procedure PT/2/4350/03, Electrical Power Source Alignment Verification. The inspectors
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which was properly addressed in the licensee's corrective actions. The inspectors ;
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evaluated the licensee's corrective actions for this event and concluded that they were adequat {
i The inspectors identified three instances in which opposite-train ECCS components were r out of service during the period of time the 2A1 KC pump was inoperable. This led to a :
concern of whether a postulated single active failure could have placed the unit outside I
its design or licensing basis, in that, if the postulated failure was the 2A2 KC pump, an l
entire ECCS function would have been compromised. NRC Inspection Manual, Part i 9900: Technical Guidance, Section 1, Operability, stated that Technical Specifications do '
allow exceptions to the requirements of the 10 CFR 50, Appendix A, General Design l Criteria (GDC) for limited periods of time. During such times, the requirements of the j single failure criterion as specified in the GDC for specific systems may not be satisfie l Therefore, having opposite-train components out of service for planned maintenance i during the period in question did not place the unit outside its design or licensing basi '
Technical Specification 3.7.3, Component Cooling Water System, requires, with only one component cooling water loop operable, that the licensee restore at least two loops to I operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least hot standby within the next six hours and e in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The component cooling water system '
had a loop inoperable from January 25,1997, and February 17,1997, and the required actions as specified in the TS were not performed. This non-compliance with TS 3. was a non-repetitive, licensee-identified and corrected violation that is being considered !
as a Non-Cited Violation (NCV), consistent with Section Vll.B.I of the NRC Enforcement Policy. It is identified as NCV 50-4.14/98-11-01: Failure to Maintain the Component Cooling Water System Operable per Technical Specification 3.7.3. This LER is close .2 (Closed) LER 50-414/97-001: Nitrogen Supply to Two Main Steam Power Operated ,
Relief Valves (PORVs) Was isolated
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This event was initially discussed in NRC Inspection Report 50-413,414/96-20 and was '
dispositioned as a NCV in inspection Report 50-413,414/97-03. This additional review l involved followup of the long-term corrective actions. The actions included revision of two periodic tests (pts) to make each valve manipulation a separate step in the procedure. PT 1/A/4200/31 A; Steam Generator PORV Stroke Test, Revision 7 and PT 2/A/4200/31A; Steam Generator PORV Stroke Test, Revision 10 were revised and approved on August 21,1997. In addition, other procedures were reviewed for steps requiring multiple actions, separated by time or distance. This resulted in revision to PT 1/A/4400/03F; Head Curve Test for KC Pumps 1 A1,1 A2,181, and 182, Revision 6, and PT 2/A/4400/03F; Head Curve Test for KC Pumps 2A1,2A2,2B1, and 2B2, Revision 1 This LER is close .
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08.3 IClosed) LER 50-414/97-005: Unit Two Reactor Trip on 2B Reactor Coolant Pump Low i Flow l An automatic reactor trip occurred on June 26,1997, while plant personnel searched for I-an electrical ground on a non-vital distribution bus. The 2B reactor coolant pump (RCP)
l lost power when its associated electrical bus was isolated. This event and its root cause l; l
.were discussed in detail in inspection Report 50-413,414/97-07. The root cause was i
!. determined to be a failure of a push button within the non-vital distribution bus. A search i
of the Operating Experience Data Base (OEDB) for the past 2 years revealed no other !
l failures for this type of push button. Therefore, this failure is considered not recurring.
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j This automatic reactor trip is bounded by discussions in Chapter 15 of the Updated Final *
l Safety Analysis Report (UFSAR). All systems responded as expected.
l l The failed push button was submitted to failure analysis. The causes were determined l l
' and the switch was replaced. Corrective actions presented in the LER were verified by :
the inspectors as completed. This LER is close '
08.4 (Closed) Violation MO) 50-413.414/97-300-01: Failure to Conduct Annual and Biennial ( Requalification Examinations within the 24-Month Training Cycle
! The Catawba licensed operator requalification training cycle covers a two-year period beginning on January 1 of odd-numbered years and ending on December 31 of l
even-numbered years. NRC inspectors observed the final week of annual operating and biennial written Licensed Operator Requalification (LOR) examinations, as documented in Sections 05.1 and 05.2 above, during the week of December 1-4,1998, which
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demonstrated the licensee's present compliance with the requirements of 10 CFR 55.59, l *Requalification." Changes to the Catawba LOR schedule were reviewed by the inspector. This forecast schedule illustrated Catawba management's intent to continue administering LOR examinations near the end of each of the next two calendar year The inspector also reviewed Catawba Operator Training Management Procedure (OTMP) 3.0," Design and Development," and noted that the definition for the start and end of Catawba's LOR cycle had been deleted. While 10 CFR 50.54(i-1) prohibits the licensee from decreasing the scope of an [NRC) approved operator requalification program, the simple deletion of start and end dates from training procedures does not
, decrease the scope of the program as long as actualimplementation dates are l continued as initially approved. As noted above, since LOR program implementation remained as originally approved by the NRC, the licensee's revision of the OTMP is not an issue. This violation is close . Maintenance l
M1 Conduct of Maintenance i M1.1 General Comments on the Conduct of Maintenance and Surveillance Activities (6270 )
i The inspectors observed portions and/or reviewed completed documentation of the following maintenance and surveillance activities: l
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IP/0/B/3560/008, Revision 5, Preventative Maintenance and Operational Check of Freeze Protection Heat Trace and instrument Box Heaters (EHT/ElB) Systems
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PT/0/B/4700/38, Revision 9, Cold Weather Protection
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MP/0/A/7450/008, Revision 9, MSA Ventilation System Filter Removal and Replacement . .
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IP/1/A/4971/001 A, Revision 002, Calibration for Brown Boveri ITE 51Y and ITE 51L Relay in general, the referenced maintenance and surveillance activities were performed well, with proper adherence to equipment calibration, radiation protection, and procedural requirement i M8 Miscellaneous Maintenance issues (92902)
M8.1 LClosed) LER 50-413/98-017: Missed Technical Specification Surveillance Requirement i on Standby Shutdown System Instrumentation Due to an inadequate Change i Management Process 1 This LER addressed a missed TS surveillance due to an inadequate change !
management process during implementation of a modification which installed the inadequate core cooling monitors at Catawba. On October 15,1998,it was discovered that the standby shutdown system (SSS) incore thermocouple reference junction box resistance temperature detector (RTD), for each unit, was not being calibrated as required by TS surveillance requirement 4.7.13.6. PlP 0-C98-3984 was generated to ;
document this issu The standby shutdown system is required to be operable in Modes 1,2, and Technical Specification surveillance requirement 4.7.13.6 stated each standby shutdown !
system instrumentation device shall be demonstrated operable by performance of a l
channel check at least once per 31 days and a channel calibration at least once per 18 months. These surveillance requirements were not being performed, and upon identification by the licensee, the missed surveillances were reported per 10 CFR 50.73 (a)(2)(i)(B).
A review of completed work orders performed by the licensee, indicated that junction box RTD number 3 on each unit was last calibrated in 1986. This was the time period during which the inadequete core cooling monitor modification was implemented. During the modification, the reference for calibrating RTD number 3 was inadvertently deleted from the model work orders. The root cause was determined to be an inadequate change management proces An engineering operability evaluation was performed subsequent to the discovery of this missed surveillance. The SSS was declared inoperable for Unit 1 and the seven-day TS LCO action statement was entered. Because Unit 2 was in Mode 4 during a refueling outage, the associated TS LCO did not appl The inspectors reviewed the licensee's corrective actions which included calibration of the junction box RTD on Unit 1 and Unit 2; the request for generation of new model work
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I orders for future calibration of the junction box RTDs; and revision of procedure l IP/0/B/3230/003, Calibration for ENA System Reference Junction Box and Deviation i
Loop. The inspectors determined these actions were appropriate for resolving this issu .This issue had little safety significance, in that the 1.5 degree Fahrenheit adjustment required to be made to the junction box RTDs would not have impacted SSS operation .. . Accordingly, the subject non-compliance with TS surveillance requirement 4.7.13.6 is recognized as a non-repetitive, licensee-identified and corrected violation that is being i
considered as a NCV, consistent with Section Vll.B.1 of the NRC Enforcement Policy. It I
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is identified as NCV 50-413,414/98-11-02: Failure to Calibrate Reference Junction Box RTDs Associated with Standby Shutdown System In-Core Detectors. This LER is
. closed.
M8.2 (Ocen) LER 50-413/96-011: Two C,hannels of Over Power Differential Temperature !
(OPDT) Inoperable All four OPDT channels on Unit 1 were calibrated on October 17,1996. Channels A and l 8 were completed on one shift and Channels C and D were completed on the next shif l
, The technicians noted that Channels A and B required more setpoint adjustment than l l
Channels C and D, prompting a licensee review of the validity of the calibration. Channel cross-checks between the four loops were done and the technicians determined that the setpoints for Channels A and B were incorrect. An engineering analysis, performed by the licensee determined that intermittently for 204 seconds during a 5% hour period, l Channels A and B were concurrently inoperable (i.e., fell below the operability limit of +/-
3% reactor power). The questioning attitude by the technicians resulted in early detection and correction of the imprcper calibration of Channels A and The inspectors were informed that the improper calibration was related to the test leads used for the calibration and an inadequate calibration procedure. According to the licensee, an intermittent resistance change in the test leads used for calibrating Channels A and B resulted in incorrect readings being used in the calibration proces Additionally, the inspectors were informed that the calibration procedure did not identify the expected results after completion of the calibration. This deficiency in the procedure contributed to the error in the setpoint for Channels A and B. Channels A and B were recalibrated and functionally checked to satisfy the conditions of TS 3.3.1. PIP 1-C-96-2789 was issued to determine the long-term corrective action The immediate and long-term corrective actions were verified by the inspectors. The long-term actions included establishing a program for replacing of the test leads at an l 18-month frequency, and requiring a statement of expected results in the work control packag l Technical Specification 3.3.1 only addresses one OPDT channel being inoperabl Accordingly, upon discovery that Channels A and B were improperly set, the licensee '
invoked TS 3.0.3, which specifies 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> to hot standby if not resolved. This TS was not violated since the improperly set channels were reset within the time limit. Pending further NRC review of the adequacy and impiementation of the procedures used to calibrate OPDT, this LER remains open.
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12 M8.3 Notification of Enforcement Discretion (NOED) 98-6-007: Missed Pressurizer Heater TS Surveillance As described in NRC Inspection Report 50-413,414/98-15, Section 08.3, the NRC exercised discretion on May 22; 1998, not to enforce compliance with TS surveillance requirement 4.4.3.3 untilissuance of an amendment to revise the subject TS. The inspectors have determined that the TS, as previously written, did not reflect plant
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design; therefore, no enforcement action is warranted. This NOED is close Ill. Enaineerina E8 Miscellaneous Engineering issues (90712,92903)
E (Closed) LER 50-413/96-012 (Revisions 0 and 1): Auxiliary Feedwater System Found Outside Design Basis
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This event was discussed in NRC Inspection Reports 50-413,414/96-20, 50-413,414/97-04, and 50-413,414/97-08. By letter dated February 18,1997, the NRC notified the licensee of an exercise of enforcement discretion in accordance with Section Vll.B.3 of the Enforcement Policy. Revision 1 of the LER was issued to describe a broader investigation and corrective actions to ensure that no further problems existe Long-term corrective actions presented in the revised LER included an investigation into the sequence of changes since the original design of the AFW system. The action was completed and approved on March 29,1997. Secondly, a reconstitution of the electrical and mechanical system design basis for the SSS interfacing systems was planned. This activity is not 100 percent completed, but is in process. The licensee is currently considering a number of options to resolve this action. Lastly, a review of the OEDB for SSS interfacing systems was conducted. This activity was completed and approved on February 26,199 The above corrective actions were reviewed and verified by the inspectors as completed or in-process. The inspectors concluded that these actions were appropriate to correct the problem. This LER is close E8.2 (Open) LER 50-413/97-001: Unanalyzed Postulated Single Failure Affecting The Steam GeneratorTube Rupture Analysis (Open) LER 50-413/97-009 (Revision 1): Unanalyzed Postulated Single Failure Affecting The Steam Generator Tube Rupture Analysis On February 10,1997, and November 18,1997, the licensee identified design deficiencies during a self-initiated design review of the accident scenario of a steam generator tube rupture (SGTR) event, described in Section 15.6.3 of the UFSAR. LER 97-001 reported a single failure which would cause the loss of power to two steam generator (SG) PORVs. LER 97-009 (Revision 1), reported that the most limiting single failure resulted in the loss of control power to two SG PORVs and the inability to isolate auxiliary feedwater flow to two SGs. These discoveries resulted in the plant being outside its design basis. The inspectors discussed these issues with plant personnel,
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reviewed the operability evaluations, corrective action plans, and PIPS 0-C97-0233 and 0-C97-362 The licensee promptly informed the NRC of the design deficiencies and submitted a notification pursuant to 10 CFR 50.72 within the required time period. Immediate actions to comply with TS were appropriately implemented for both discoveries as described in the LERs. The operability evaluations supported the actions and adequately demonstrated the operability of the system in a degraded conditio The root cause of the design deficiencies, as presented in the LERs, was attributed to ;
less-than-adequate review when implementing the generic Westinghouse SGTR !
analysis methodology in 1987. The inspectors concluded that the specific corrective actions to resolve the immediate concerns described in both LERs have been completed by the license The UFSAR, Section 10.3, Main Steam Supply System, and Section 15.6.3.1, Steam Generator Tube Failure, states that the control room operators can isolate the feedwater flow to terminate the radioactive release to the atmosphere from the affected SG. The UFSAR also states that the PORV and its electric motor operated block can be used to isolate a failed or stuck open PORV to stop the uncontrolled steam flow from a failed S LER 97-001 describes a single failure that may cause loss of power to two PORVs, resulting in the inability to perform the action stated in the UFSAR. Likewise, LER 97-009 (Revision 1) describes a single failure that would result in loss of the 125 volt direct current Vital Distribution Center, causing the loss of control power to two SG PORVs and the inability to isolate auxiliary feedwater flow to two SGs; again prohibiting the operator actions as stated in the UFSAR. The SGTR safety analysis assumes the ability to control feedwater to a failed SG. Without this control, the radiological consequences could allow a release to the environment in excess of allowable. The allowable release is presented in calculation CNC-1227.00-00-0073, Revision 0, Steam Generator Tube Rupture Dose Analysis Calculatio LER 97-001 was discussed in NRC Inspection Report 50-413,414/97-05. Additional followup was done during this inspection. The inspectors verified that TS 3.7.1.6 was revised and issued as Amendment 159 for Unit 1 and 151 for Unit 2. A failure modes and effects analysis has been performed, as described in the LER, and documented in calculation CNC-1381-05-00-0181. Also, the licensee's safety analysis group has completed RETRAN 02 analysis for SG overfill. The analysis is documented in calculation CNC-1552.08-00-0266. The inspectors concluded that the corrective actions, 4 described in the LER, have been complete LER 97-009 (Revision 1) was briefly discussed in NRC Inspection Report
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50-413,414/97-14. Additional followup was done during this inspection. On November '
18,1997, the immediate corrective actions implemented were the establishing of conservative, administrative controls limiting the primary system equilibrium and transient lodine-131 dose equivalent concentration to ensure the offsite doses were bounded by the analysis of UFSAR Chapter 15, Safety Analysis. A more realistic limit on lodine-131 dose equivalent activity was approved on January 15,1998, whic.h remains in effect while maintaining consequences within licensed limit Long-term corrective actions for LER 97-009 (Revision 1) have not been determined by the licensee. A modification is currently under review by the licensee, but has not yet
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been finalized. Therefore, pending additional NRC review of the long-term corrective
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actions associated with this LER, both LERs will remain ope ;
IV. Plant Support R2 Status of Radiation Protection (RP) Facilities and Equipment R Process and Effluent Radiation Monitors Inspection Scope (84750) !
The inspectors reviewed selected licensee procedures and records for required surveillances on the meteorological tower and process and effluent radiation monitor l The inspectors also reviewed licensee records regarding radiation monitor availability l
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and the results of the licensee's 1997 Annual Liquid and Gaseous Effluent Report and Annual Radiological Environmental Operating Report 199 Observations and Findinas !
During tours of the auxiliary building, radwaste building, turbine building and waste monitor tank building, the inspectors observed the physical operation of process radiation effluent monitors (EMFs) in service. The inspectors reviewed selected radiation and process monitor surveillance procedures and records for performance of channel checks, source checks, channel calibrations, and channel operational tests. The inspectors determined the licensee was performing checks described in TS, and Selected Licensee Commitments Chapter 16.11. For the EMF year-to-date (11 months) monthly rolling availability, monitors required by TS were available 98.97 percent of the time and monitors not required by TS were available an average of 99.18 percen ,
The inspectors reviewed selected licensee procedures and records for required surveillance on the meteorological tower and independently verified meteorological tower wind direction indications. The inspectors verified operation of data output values and chart drives in the control roo The inspectors selectively reviewed the 1997 gaseous and liquid releases and their associated dose calculations and determined that the doses at the maximum location (Site Boundary, 0.5 miles, NE Sector) were small percentages of the annual dose limits i of 40 CFR 190.10(a)e These limits are 25 mrem whole body,75 mrem to the thyroid, and 25 mrem to any other organ. The reported values were 1.84E-01 mrem whole body and 9.97E-01 mrem maximum organ dose Concentrations of radioactive isotopes observed in the environment in 1997 for the licensee's related radionuclides were reviewed and compared to data from previous l: years and it was determined that the releases from 1997 were generally comparable to :
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concentrations observed in past Annual Radiological Environmental Operating Report The total body dose estimated to the maximum exposed member of the public as calculated by environmental sampling data, excluding Thermoluminscent Dosimeter
! results, was 4.08E-01 mrem for 1997.
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15 Conclusions The inspectors concluded radiation and process effluent monitors and environmental monitors were being maintained in an operational condition in compliance with TS ,
. requirements and Updated Final Safety Analysis Report comn itments. Offsite doses l from radioactive effluents were small percentages of the annuai .'ose limits of 40 CFR 190.10(a).
R2.2 Transportation of Radioactive Materials ~ Inspection Scope (86750)
l The inspectors evaluated the licensee's transportation of radioactive materials program i
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 Observations and Findinos
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The inspectors reviewed selected procedures and determined that they adequately !
addressed the following: (1) assuring that the receiver has a license to receive the )
material being shipped; (2) assigning the form, quantity type, and proper shipping name ;
l of the material to be shipped; (3) classifying waste destined for burial; (4) selecting the '
L type of package required; (5) assuring that the radiation and contamination limits were met; and (6) preparing shipping papers.
! The inspectors reviewed the training records for individuals assigned responsibilities for {
shipping under the requirements of 49 CFR 172.700 and found that the designated site l
individuals met the training requirements for course subject matter and timelines ]
The inspectors reviewed a sample of shipping papers and receipt surveys. The l inspectors determined that the shipping papers were complete and that the shipping and receipt surveys met regulatory requirement l Conclusions Based on the above reviews, the inspectors determined that the licensee had implemented a program for shipping and receiving radioactive materials as required by NRC and DOT regulation I V. Manaaement Meetinas l X1 Exit Meeting Summary l
L The inspector presented the inspection results to members of licensee management at the conclusion of the inspection on December 16,1998. The licensee acknowledged the findings presented. No proprietary information was identifie I
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PARTIAL LIST OF PERSONS CONTACTED I L
l Licensee l M. Boyle, Radiation Protection Manager- !
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S. Bradshaw, Safety Assurance Manager .
G. Gilbert, Regulatory Compliance Manager R. Glover, Operations Superintendent .
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P. Herran, Engineering Manager R. Jones, Station Manager G. Peterson, Catawba Site Vice-President '
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- F. Smith, Chemistry Manager i
- , R. Parker, Maintenance Manager- I l
INSPECTION PROCEDURES USED
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IP 37551: Onsite Engineering .
IP 40500: Effectiveness of Controls in Identifying, Resolving, and Preventing Problems IP 61726: Surveilltsnce Observations IP 62707: Maintenance Observations i
IP 71001: Requalification inspection IP 71707; Plant Operations
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l D IP 71714: Cold Weather Preparations IP 71750: Plant Support Activities IP 84750: Radioactive Waste Treatment, and Effluent and Environmental Monitoring l IP 86750: Solid Radioactive Waste Management and Transportation of Radioactive
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Materials IP 90712: In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Followup - Operations
.lP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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l l ITEMS OPENED, CLOSED, AND DISCUSSED ;
Opened i
50-414/98-11-01 NCV Failure to Maintain the Component Cooling Water '
System Operable per Technical Specification 3. l (Section 08.1) l
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50-413,414/98-11-02 NCV Failure to Calibrate Reference Junction Box RTDs I
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Associated with Standby Shutdown System In-Core
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Detectors (Section M8.1)
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50-413/98-16 LER Missing Interlock Discovered During Design Review on ECCS Pump Area Sump Pumps Caused Plant to be in a Condition Outside the Design Basis (Section 01.3)
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l 50-414/97-003 LER Component Cooling System Unavailability (Section l 08.1)
l 50-414/97-001 LER Nitrogen Supply to Two Main Steam Power i Operated Relief Valves Was isolated (Section 08.2)
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50-414/97-005 LER Unit Two Reactor Trip on 28 Reactor Coolant
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l PumprLow Flow (Section 08.3)
. 1 50-413,414/97-300-01 VIO Failure to Conduct Annual and Biennial Requalification Examinations within the 24-Month Training Cycle (Section 08.4)
50-413/98-017 LER Missed Technical Specification Surveillance !
Requirement on Standby Shutdown System l Instrumentation Due to an inadequate Change
! Management Process (Section M8.1) l 50-413/96-012 (Rev 0 & 1) LER Auxiliary,Feedwater System Found Outside Design Basis (Section E8.1) l L
Discussed 50-413/96-011 LER Two Channels of Over Power Differential Temperature Inoperable (Section M8.2)
50-413/97-001 LER Unanalyzed Postulated Single Failure Affecting The Steam Generator Tube Rupture Analysis (Section E8.2)
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50-413/97-009 (Rev 1) LER Unanalyzed Postulated Single Failure Affecting The i
Steam GeneratorTube Rupture Analysis (Section EB.2)
LIST OF ACRONYMS USED l CFR -
Code of Federal Regulations CLA -
Cold Leg Accumulator CR -
Main Control Room DOT - Department of Transportation'
ECCS - Emergency Core Cooling System EMF -
Effluent Monitors FlP -
Failure investigation Process l GDC -
General Design Criteria JPM -
Component Cooling Water (licensee's system designation)
LCO -
Limiting Condition for Operation LER -
Licensee Event Report LOR -
Licensed Operator Requalification NCV -
Non-Cited Violation ND -
Residual Heat Removal (licensee's system designation)
NEG -
Negative Observation (Executive Summary template code)
NI -
Safety injection (licensee's system designation)
NSD - Nuclear System Directive OPDT - Over Power Differential Temperature
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OTMP- Operator Training Management Procedure
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PIP -
Problem Investigation Process PORV - Power Operated Relief Valve POS -
Positive Observation (Executive Summary template code)
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Periodic Test RCP -
Reactor Coolant Pump l RO -
Reactor Operator l RTD -
Resistance Temperature (or thermal) Detector SG -
Steam Generator SGTR - Steam Generator. Tube Rupture SRO -
Senior Reactor Operator l SSS - Standby Shutdown System l TS -
Technical Specification ,
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TSAIL - Technical Specification Action item Log i UFSAR- Updated Final Safety Analysis !
VIO -
Violation l j l \
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