IR 05000413/1999005
| ML20217A847 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 09/24/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20217A795 | List: |
| References | |
| 50-413-99-05, 50-414-99-05, NUDOCS 9910120097 | |
| Download: ML20217A847 (26) | |
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- x;w~n.u. , - ~. .F U.S. NUCLEAR REGULATORY COMMISSION REGION ll Docket Nos: 50-413,50-414 License Nos: NPF-35, NPF-52 Report Nos: 50-413/99-05, 50-414/99-05 Licensee: Duke Energy Corporation Facility: Catawba Nuclear Station, Units 1 and 2 Location: 422 South Church Street Charlotte, NC 28242
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Dates: July 18 - August 28,1999 I
inspectors: D. Roberts, Senior Resident inspector !
R. Franovich, Resident inspector '
M. Giles, Resident inspector W. Bearden, Reactor inspector (Sections M8.3, M8.4) ,
R. Carroll, Project Engineer (Sections M8.1, M8.2, M8.3) l P. Fillion, Engineering Inspector (Section E1.1) .
E. Christnot, Resident inspector, Oconee Nuclear Station (Section M1.1)
R. Moore, Engineering inspector (Sections E8.2, E8.3, E8.4, E8.5)
P. Tam, Senior Project Manager (Section E3.1)
D. Thompson, Security inspector (Sections S1.1, S3.1, S5.1, S7.1)
F. Wright, Senior Radiation Specialist (Sections R1.1, R1.2, R7.1)
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_ Approved by: C. Ogle, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure 9910120097 990924 PDR G ADOCK 05000413 pg
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EXECUTIVE SUMMARY 1:. w 3 3 .s c -: #
Catawba Nuclear Station, Units 1 and 2 NRC Inspection Report 50-413/P9-05,50-414/99-05 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspection as well as the results of announced inspections by regional reactor safety inspectors, a resident inspector from the Oconee station, and a Senior Project Manager from the Office of Nuclear Reactor Regulation. [ Applicable template codes and the assessment for items inspected are provided below.)
Operations
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The licensee's one-hour event notification of a Unit 2 forced shutdown in accordance I with technical specifications was provided seven hours after the unit shutdown was initiated. As a result, a non-cited violation was issued for failure to submit the NRC notification in the time required. (Section E8.5; [NCV - 5A])
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Nuclear Safety Review Board members asked probing questions that were appropriately focused on nuclear safety and compliance with regulatory requirements. (Section 07.1;
[POS - 5A])
Maintenance
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A non-cited violation was identified for failure to follow maintenance procedures, requiring maintenance technicians to fill the 1 A auxiliary feedwater pump motor bearing
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housing to the correct capacity in accordance with information in the vendor manua This caused a failure of the 1 A auxiliary feedwater pump motor inboard bearing during post-maintenance testing. (Section M1.2; [NCV - 3A])
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A non-cited violation was identified conceming a failure to perform ice condenser lower inlet plenum and tuming vane inspections per Technical Specification requirement (Section M8.1; [NCV- 2B,4C])
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A non-cited violation was identified concerning inadequate engineered safety features actuation system response time test procedures that resulted in missed Technical Specification required surveillance of the reactor trip function from safety injection on containment pressure - high and pressurizer pressure -low. (Section M8.2; [NCV - 2B, 4C])
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A non-cited violation was identified concerning inadequacies in hydrogen skimmer system response time test procedures. (Section M8.3; [NCV - 28,4C])
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A non-t,ited violation was identified concerning a failure to perform turbine trip - reactor trip testing required by Technical Specification 3.3.1.15. (Section M8.4; [NCV - 2B,4C])
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Based on a review of three circuits, the inspector concluded that safety-related logic circuits were presently being tested in accordance with Generic Letter 96-01, Testing of Safety-Related Logic Circuits. (Section E1.1; [POS - 28])
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~stp-- 32 . ' The licensee's res' ponse to Generic Letter 96-01, dated May 20,1997, incorrect (
concluded that all portions of the applicable logic circuitry were being adequately tested such that existing statior. Technical Specifications were fulfilled. (Section E1.1; [NEG -
4C]) ~
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A non-cited violation was identified for inadequate Technical Specification Surveillance Requirement 4.8.1.1.2 (g) (4) testing for logic relays in the emergency diesel generator start circuit. (Section E1.1; [NCV - 28,4C])
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Revision 7 of the Catawba Updated Final Safety Analysis Report complied with the provisions of Title 10 of the Code of Federal Regulations Section 50.71. (Section E3.1;
[POS - 4A])
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A non-cited violation was identified for two examples of inadequate corrective actio These examples involved a failed relay on the turbine driven auxiliary feedwater pump and degradation in the control room chillers. (Sections E8.2, E8.3; [NCV- 2A, SC])
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A non-cited violation was identified for inadequate corrective action with respect to identifying degraded service water supply piping to auxiliary feedwater pumps. (Section E8.5; [NCV - 2A, SC])
Plant Suooort i
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Licensee radiation surveys, postings, access controls, and radiological work controls ;
were effective and performed in accordance with regulatory requirements. (Section R1.1; [POS - 1C))
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High radiation areas were properly controlled. (Section R1.1; [POS - 1C])
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Licensee procedures for controlling divers in radiological areas were adequate. (Section R1.1; [POS - 1C))
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- All individual personnel radiation exposures were less than regulatory limits. (Section R1.1; [POS - 1C])
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Better engineering support, work control planning and coordination, and effective l shutdown chemistry procedures were factors contributing to the site's lowesi >utage collective radiation dose. The Catawba program to keep radiation dose as low as reasonably achievable was effective in the continued reduction of the site's collective personnel radiation dose. (Section R1.2; [POS - 1C])
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.The radiation protection personnel were ehectively utilizing the corrective action program 1 to make program improvewnts and correct identified program deficiencies or '
non-compliance issues. (oection R7.1; [POS SA, SB, SC])
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The licensee's use of technical resources during radiation protection program audits was 1 an effcctive tool to improve radiation protection performance and compliance. (Section !
R7.1; [POS - 1C, SA]) i
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The licensee met regulatory requirements concerning personnel access in and out of the 1 facility protected area. (Section S1.4; [POS - 1C])
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The Physical Security / Contingency Plan changes did not decrease the security program effectiveness. (Section S3.1; [POS - 1C])
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. Security officers were appropriately trained and qualified to perform their duties in accordance with the licensee's Training and Qualifications Plan. Conduct of contingency drills and implementation of defensive strategies were considered security program strengths. (Section S5.1; [POS - 1C, 3B])
Licensee-conducted audits were thorough, complete, and effective in terms of
- uncovering weaknesses in the security system, procedures, and practices. The audit findings and recommendations were reviewed, appropriately assigned, analyzed, and prioritized for corrective action. The corrective actions taken were technically adequate and performed in a timely manner. The audit /self-assessment program continues to be a strength. (Section S7.1; [POS 5A,58, SC])
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Report Details
E"% 'Summ'as of Plant Status
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Unit 1 began the inspection period at or near 100 percent power. On August 20,1999, reactor power was decreased to 88 percent for turbine control valve movement testing. Power was restored to 100 percent on August 21,1999, where it remained for the duration of the report perio Unit 2 operated at or near 100 percent power during the report perio l. Ooerations 01 Conduct of Operations O1.1 General Comments (71707)
l The inspectors conducted frequent control roorr 'ours to venfy proper staffing, operator attentiveness and effective communications, ano adherence to approved procedure The inspectors: (1) e' tended operations shift tumovers and site direction meetings to maintain awareness of overall plant status ano operations; (2) reviewed operator logs to verify operational safety and compliance with Technical Specifications (TS); (3)
periodically reviewed instrumentation, computer indications, and safety system lineups, along with equipment removal and restoration tagouts, to assess system availability; (4)
reviewed the TS Action item Log for both units daily for potential entries into limiting conditions for operation (LCO) action statements; (5) conducted plant tours to observe material condition and housekeeping; and (6) routinely reviewed Problem Identification Process reports (PIPS) to ensure that potential safety concems and equipment problems were resolved. The inspectors identified no major problems from these review O2 Operational Status of Facilities and Equipment O Emeraency Diesel Generator (EDG) System Walkdown (71707)
The inspectors performed a detailed walkdown of the 2A EDG and the jacket water l cooling, fuel oil, and starting air support systems. The inspectors verified that the systen)
configuration, including valvo and breaker positions, was in accordance with procedures and system drawings; technical specification surveillance requirements fuere being met; chemistry sampling records of new fuel oil were in compliance with American Society for Testing and Materials (ASTM) specifications; and completed instrument calibration procedures indicated that instrument setpoints were adjusted properly. Minor procedural deficiencies were identified and communicated to the licensee for correctio . 07 . Quality Assurance in Operations 0 Meetinc of the Nuclear Safety Review Board (NSRB) (40500)
The inspectors observed a portion of the NSRB, which met at the Catawba Nuclear Station August 17-19,1999. The inspector = concluded that NSRB members asked probing questions that were appropriately focused on nuclear safety and compliance with regulatory requi.ement ..
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11. Maintenance
M1 Conduct of Maintenance M1.1 General Comments on the Conduct of Maintenance and Surveillance Activities (6270 )
The inspectors observed all or portions of the following maintenance and surveillance activities:
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PT/2/N4350/002A, Revision 65 Diesel Generator 2A Operability Test
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OP/2/A/6350/002, Revision 93, Diesel Generator Operation
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PT/2/A/4550/004, Revision 13, D/G Fuel Oil Storage Tank Water inspection
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OP/2/A/G550/001, Revision 38, Diesel Generator Fuel Oil System Operaticn
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OP/0/A/6400/046, Revision 08, Operating Procedure For Sampling Oil System
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PT/1/A/4250/003A, Revision 49, Aux Feedwater Motor Driven Pump 1A Performance Test
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PT/1/A/4400/009, Revision 46, Cooling Water Flow Monitoring For Asiatic Clams And Mussels Quarterly Test
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Work Order 98157277, Replace Motor Fan on 1B Diesel Generator Pre-lube Pump
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Work Order 98188984, PM on Check Valve for Starting Air Dryer 1B1 I The above maintenance and surveillance activities were generally conducted with proper adherence to procedures and appropriate adherence to equipment calibration and radiation protection requirement M1.2 Failure of the 1 A Auxiliarv Feedwater Pumo Motor Bearina Inspection Scope (62707. 61726)
I On August 2,1999, auxiliary feedwater (AFW) pump motor 1 A experienced an inboard bearing failure following preventive maintenance (PM) on the pump and inotor. The inspectors reviewed procedures goveming the PM, interviewed maintenance pm sonnel who performed the PM, reviewed the pump vendor manual and the licensee's j
Lubrication Manual, observed maintenance activities and post-maintenanca testing associated with pump motor replacement, and reviewed the licensee's root cause )
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determinatio Observations and Findinas
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.The PM activities performed on August 2,1999, consisted primarily of replacing bearing lubricating oil for the AFW pump and motor. A failure of the motor in-board bearing occurred during post-maintenance testing and was subsequer,tly attributed to a lack of bearing lubrication. The pump motor was replaced and, on Augus.t 5, was successfully !
tested and declared operable within the 72-hour outage time allowed by TS Action 3.7. The inspectors determined that maintenance procedurs MP/0/A/7650/002, Revision 9 Lubrication of Safety Related Equipment, provided instfuctions for the maintenance activities. This procedure was provided to satisfy the requirement of TS 5.4.1 for i
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. intenance on safety-related equipment. Step 11.11 directed main +enance r
technicians to reference the Lubrication Manual for proper !ubricant type and component capacity. This step also directed the workers to determine proper capacity per component tag and/or manufacturer's manualif the capacity was unknown. According to the motor vendor manual, CNM 1318.16-0034-001, Step 6.2.27, bearing reservoirs were to be filled with oil to the center of the sight glass using turbine oil with a viscosity of 220 Saybolt Universal Seconds at 100 degrees Fahrenheit (F) at a capacity of approximately one quart per bearing. The maintenance technicians documented that the type of lubricant used was Terristic-32; the volume was four quarts. Step 11.1.7 of the procedure directed maintenance technicians to fill the component to the correct capacity with the specified oil and referred back to the information provided in step 11.1. i. Both steps were signed and dated. However, according to the licensee's root cause *
determination, only four ounces (0.125 quart) of oil were found in the inboard bearing reservoir following the bearing failure. The maintenance technicians indicated that they did not measure the amount of lubricating oil that was added to each bearing and relied only on sight glass indication. The licensee's root cause determination concluded that the sight glass was fouled and not a reliable indicator of the quantity of oil contained in the bearing reservoir. As such, the technicians did not properly verify that approximately one quart of oil was replaced. The inspectors concluded that the maintenance technicians failed to follow the procedure in that the inboard bearing reservoir was not filled to the correct capacity. This failure to follow the procedure constituted a violation of TS 5.4.1. The licensee's proposed corrective actions involved procedural enhancements that would specifically require volumetric measurement of lubricating oil for each bearing reservoir. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PIP C-99-3132. This item is identified as NCV 50-413/99-05-01: Failure to Follow Procedure Governing AFW Pump Motor Maintenanc Conclusions The 1 A AFW pump motor inboard bearing failed during post-maintenance testing as a result of inadequate maintenance. An NCV was identified for failure to follow maintenance procedures requiring maintenance technicians to fill the motor bearing to the correct capacity in accordance with information in the vendor manual. This error caused a failure of the 1 A AFW pump motor inboard bearing during post-maintenance tutin MB Miscellaneous Maintenance issues (92902,92700)
M8.1 (Closed) Licensee Event Reoort (LER) 50-413/98-015-(00. 01): Technical Specification
. Required Shutdown and Operation Prohibited by Technical Specifications Associated with the Ice Condenser (Closed) Notice of Enforcement Discretion (NOED) 98-6-015: Catawba Unit 2 Ice Condenser Flow Passage inspection Wnh the exception of not including the lower inlet plenum and turning vanes as part of l the nine-month ice condenser flow passage inspection required by TS 4.6.5.1.b.2, all the l ice condenser issues discussed in the subject LER were dispositioned as NCVs per l NRC enforcement action (EA 98-477) letter dated August 2,1699. Due to reasons of i
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M& .w. > - in~ accessibility while at power, NOED 98-6-015 was granted on August 13,1998,io aliow for a delay in the inspection of the Unit 2 ice condenser lower inlet plenum and turning vanes until after the unit was shut down for its refueling outage in September 1998. The NOED didn't apply to Unit 1 since it was already shut down for extensive ice condenser inspections. Recognized as a missed surveillance, TS amendments were subsequently made for Units 1 and 2 (Amendments 172 and 163, respectively) to reflect an 18-month (versus nine-month) frequency for the visual inspections of the lower inlet plenum support structures and tuming vanes. The inspectors confirmed that this revised 18-month requirement is currently reflected in the improved TS under Surveillanco Requirement 3.6.12.2, as well as in procedure SM/0/A/8510/010, Cleaning and inspection of Ice Condenser Flow Passages. This Severity Level IV violation of TS 4.6.5.1.6.2, is being treeied as a NCV, consistent with Appendix C of the NRC Enforcement Policy. This violation, like all the other ice condenser issues addressed in
- this LER, is captured in the licensee's corrective action program under PIP 1-C98-278 It will be identified as NCV 50-413,414/99-05-02: Failure to Perform Ice Condenser Lower Inlet Plenum and Tuming Vane inspections per TS Requirements. Based en the above, LER 50-413/98-15 and NOED 98-6-015 are close >
M8.2 (Closed) LER 50-413/98-018-00: Inadequate Procedures for Engineered Safety Features Actuation System (ESFAS) Response Time Testing Cause Failure to Satisfy TS Requirements l
During an implementing procedure review for TS Surveillance Requirement 4.3.2.2, I Engineered Safety Features Response Time, the licensee identified that there was no procedure that verifiec: the response time for the reactor trip function from safety injection I on containment pressure - high or pressurizer pressure - low, it was determined that this !
c.ondition constituted a missed surveillance and the 24-hour surveillance performance !
provision of TS 4.0.3 was applied to Units 1 and 2. Both units subsequently exited TS I 4.0.3 after the response times were demonstrated to be within the TS allowable limit (i.e.,
less than or equal to 2 seconds) by adding up the times from individual tests performed on sections of the trip circuitry. As the time for the solid state protection system (SSPS)
electronics (logic) was not specifically measured in a test, a 20 millisecond time was assumed for that portion of the circuit by taking credit for the semi-automatic SSPS logic tester. This assumption was considered conservative, considering the tester verifies the SSPS logic within 2 milliseconds. As a fallout from this issue, the licensee initiated a similar review of the remainder of the ESFAS functions to confirm sufficient overlap in response time testing between the SSPS electronics portion of the circuitry and the mechanical portion (i.e., actuation devices). Except for two cases, it was found that the mechanical tests did not specifically include a measurement of the SSPS electronic Howeverl since the acceptance criteria did include a conservative time allowance for the associated sensor and the SSPS electronics, these ESFAS functions were determined to
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be operable. The inspector verified that the newly developed series response time procedures for Unit 1 (IP/1/A/3200/016 and 017, Response Time Testing of Reactor Protection System and Engineered Safety Features Loops) appropriately included: (1)
the required response time testing for the reactor trip function from safety injection on j containment pressure - high and pressurizer pressure - low; and (2) the SSPS logic response time in the overall ESFAS time response verification circuit testing. Because of an apparent reliance on the semi-automatic logic tester to account for SSPS logic response time in some cases, the inspector confirmed that verification and measurement of the logic tester signal pulse combinations and width were included in the newly developed Unit 1 procedures IP/1/A/3200/015 A and B,1SSPS Train A (B)
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~ Outage Testing and Maintenance. All of the aforementioned procedures were u$lized during the last Unit 1 refueling outage (1EOC11). The corresponding procedures for Unit 2 were scheduled for completion in October 1999, in preparation for the upcoming 2EOC10 outage. Captured in the licensee's corrective action program under PIP 1-C98-4775, this Severity Level IV violation of TS 5.4.1 is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy. It will be identified as NCV 50-413,414/99-05-03: Inadequate ESFAS Procedures Result in Missed TS Surveillanc M8.3 (Closed) Unresolved item (URI) 50-413.414/99-01-01: ESFAS Response Time Testing for Hydrogen Skimmer (VX) Fan Suction isolation Valves On March 4,1999, the licensee made a one-hour non-emergency 10 CFR Part 50.72 report when Unit 2 entered TS 3.0.3 after identifying an apparent discrepancy between the acceptance criterion specified in surveillance test procedure PT/1(2)/A/4200/09, Engineered Safety Features Actuation Periodic Test, and TS surveillance requirement (SR) 3.3.2.10, which required ESFAS response times (RT) be verified within UFSAR limits every 18 months. The surveillance test acceptance criterion for the VX system was that fan suction valves 1(?)VX 1 A and 1(2)VX-28 stroke fu!I open in less than or equal to 664.8 seconds; whercas, the maximum RT specified in Table 7-15 of the UFSAR for VX system operation was 600 seconds. During review of the most recent surveillance tests to determine if the performance data were within the specified UFSAR limit, the licensee determined that the RT of Unit 2 A and 8 train suction valves (2VX-1 A and 2VX-28, respectively) exceeded 600 seconds. Accordingly, both trains of the Unit 2 VX system were declared inoperable and TS 3.0.3 was entered. The timer relay associated with valve 2VX-2B was subsequently recalibrated to reduce the delay time and Unit 2 exited TS 3.0.3. Similarly, the timer relays for VX suction valves 1VX-1 A, 1VX-2B, and 2VX-1 A were also recalibrated after further revie By design, the VX system suction valves will open on a containment high-high pressure signal once their respective timer relay times out. Then, as soon as the suction valve limit switch moves off the closed position, a permissive is made up in the associated VX fan start circuit. Reflecting this operation, the licensee's subsequent operability analysis (included in PIP 0-C99-0578) concluded that the VX system design basis requirements had been satisfied all along. Specifically, it was determined that the maximum RT of 600 seconds for VX system operation applied to the VX system fans starting rather than the suction valves fully opening. Past revisions of PT/1(2)/A/4200/09 (i.e., prior to taking credit for PT/1(2)/A/4450/05A(B), Containment Air Return Fan 1(2)A(B) and Hydrogen Skimmer Fan 1(2)A(B) Performance Test, in 1997 for Unit 1 and in 1995 for Unit 2)
appear to support this determination, in that a verification of the fans starting prior to exceeding the maximum 600-second RT was included in the acceptance criteria along with the aforementioned valve stroke time. After reviewing PIP 0-C99-0578, the Updated
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. Final Safety Analysis Report WFSAR), and associated logic diagrams, the inspectors
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also concluded that the 600 seend maximum RT applied to the time from when the {
i high-high containment pressure occurs to when the VX system fans star Aside from preparing a change to UFSAR Table 7-15 to clarify that the maximum VX system RT applies to fan operation, the licensee also prepared changes [ Revisions 165N (1400)] to PT/1(2)/A/4200/09 that increased the allowable VX suction valve R Specifically, the . maximum allowable VX suction valve RT was changed from 66 seconds to 666.8 seconds for simulated loss of coolant accident (LOCA) testing, and
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testing. The assumptions made in support of these changes were as follows:
Time (seconds) Bemarks <
Time (seconds) Remarks 600 maximum time delay 66 previous maximum for VX system ooeration RT for VX suction valves 66 maximum VX suction valve stroke time 2 - SSPS/ instrument delay (- 1.2) accounting for instrument / electrical Total: 66 new LOCA RT and OAC scan maximum RT for VX suction valves Total: 66 previous maxim.um RT for VX suctior, valves 11 maximum ESFAS RT for emergency diesel and sequencing of VX fan / valve timer relays Total: 67 new LOCA/ LOOP maximum PT for VX suction valves
. The inspectors determined that the increase in maximum RT was not appropriate, since the previous RT (664.8) already reflected any additions with respect to the emergency diesel, load sequencer, instruments, and SSPS. This determination was based on the fact that: (1) it requires suction valve limit switch movement off the closed position to make up a start permissive for the associated VX fan; and (2) the maximum allowable
' RT for VX fan operation is 600 seconds, which encompasses both LOCA and LOCA/ LOOP conditions. Accordingly, this change resulted in an inadequate procedur In addition, a review of the current document control copy of the procedure revealed a
- maximum allowable RT of 667.8 seconds for the VX suction valves for both LOCA and LOCA/ LOOP testing. Appearing to be a case of incorrectly incorporating the intended change, this too resulted in another example of an inadequate procedur , - As indicated previously, with the exception of verifying the actuation of a load sequencer relay permissive in the VX fan starting circuit, the licensee no longer performs the 18-month ESFAS RT testing of the VX fans in PT/1(2)!A/4200/09; instead credit is taken for PT/1(2)/A/4450/05A(B). - There was, however, no apparent indication of this credit being
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.taken in either one of these procedures. A review of the applicable sections of PT/1(2)/A/4450/05A(B) revealed that it performs the quarterly test of the start permissive interlock between the VX valves and their associated fan (TS SR 3.6.8.3), as well as performs a quarterly test that verifies the VX fans start on an actuation signal after a concuirent valve and fan timer delay inclusively between 480.2 seconds and 59 seconds (TS SR 3.6.8.4). The maximum allowable RT of 599.8 seconds does not
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Though a review of recent test results found no current opereN(issues (primarily to the present calibration margin in the VX fan and valve timers), this inappropriate maximum allowable RT resulted in a thiid example of an inadequate procedure. All three examples of inadequate procedures are in non-compliance with TS 5.4.1, ,
Captured in the licensee's corrective action program as PIP C-99-03356, these three {
examples comprise a Severity Level IV violation that is being treated as an NCV, i consistent with Appendix C of the NRC Enforcement Policy. It will be identified as NCV 50-413,414/99-05-04: Inadequate VX System Test Procedure i M8.4 (Closed) LER 50-413/9P-005-00: Surveillance Requirements for Turbine Trip - Reactor "
Trip Functions incorrect y Performed Causing Technical Specification Non-compliance (Closed) LER 50-413/99-005-01: Surveillance Requirements for Turbine Trip - Reactor Trip Functions incorrectly Performed Due to Lack of Understanding of Test Requirements On March 17,1999, the licensee determined that TS 3.3.1.15 (Reactor Trip System Instrumentation) had not been properly implemented. TS 3.3.1, Limiting Condition for Operation, required that the reactor trip system instrumentation for each function in Table 3.3.1-1 be operable. Table 3.3.1-1 required, in part, that the turbine electro hydraulic pressure low and turbine stop valve closure reactor trip functions be operable when the unit is in Mode 1 at power levels above the P-9 interlock (power range neutron flux approximately 69% power). Surveillance requirements for TS 3.3.1.15 were applicable
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for both functions and required performance of a trip actuating device operational test (TADOT) prior to reactor startup. TS 3.3.1.15 contained a note that this testing was only required if not performed within the previous 31 days. The licensee determined that existing channel calibration instructions for the main turbine hydraulic oil system low pressure switches and limit switches, which were performed during each scheduled refueling outage, fulfilled the requirements for TADOT testing for both function However, no controls had existed to verify performance of this testing prior to other startups such as from unplanned equipment maintenance outages. The licensee had previously considered the TADOT testing satisfied during the monthly main turbine valve movement testing. This testing included an exercise of the main turbine stop valves and verified that the proper SSPS lights illuminated. However, this testing did not include a requirement to test both trains of SSPS. This periodic test would have been adequate to satisfy the SR if both trains of SSPS had been tested and had adequate controls existed to ensure testing was performed prior to reactor startup if not performed within the previous 31 days. The licensee attributed the failure to ensure adequate testing to insufficient understanding of the TS requirements for the TADOT testing for these two
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reactor trip function When the condition was discovered the licensee declared these reactor trip functions )
inoperable on Unit 1 since the required TADOT testing had not been performed prior to j the most recent reactor startup. These 'lunctions were operable on Unit 2 since that unit had not been shutdown since the most recent refueling outage when a channel
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calibration was performed. The licensee immediately entered TS 3.0.3 on Unit 1 and performed TADOT testin I
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W;e" u.c. < Fdr corrective actions, the licensee revised the channel calibration instruction toinclude a separate new section for performir,g TADOT testing when a complete channel calibration was not required. Additionally, work requests were added to the Unit 1 and 2 unplanned outage lists to require completion of TADOT testing prior to reactor startup.
f The inspectors verified that Catawba Procedure, IP/1/A/3040/005, Calibration Procedure /TADOT for Main Turbine Hydraulic Oil System Pressure Switches and Limit Switches, Revision 21, had been revised. Additionally, the inspectors verified that work requests 98070421 and 98088217 had been added to the Unit 1 and 2 unplanned outage lists, respectively, to require completing TADOT testing prior to reactor startu The failure to perform required turbine trip-reactor trip TADOT testing constituted a violation of TS 3.3.1.15. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as P;P 0-C99-0973. It is identified as NCV 50-413,414/99-05-05: Missed Turbine Trip - Reactor Trip Testing Required by TS 3.3.1.15. This LER is close . Enaineerina E1 Conduct of Engineering
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E Testino of Safety-Related Loaic Circuits 1 Inspection Scope (Tl 2515/139)
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The inspectors reviewed the Technical Specification surveillance testing of the following three system functions:
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Start signal for the turbine driven auxiliary feedwater pump
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- Automatic switchover of emergency core cooling system (ECCS) water source from the refueling water storage tank (RWST) to the containment sump
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- Emergency diesel generator (EDG) start signal These system functions were chosen for review from probabilistic risk a'ssessment insights. The inspection was performed using the guidance of Temporary Instruction 2515/139, inspection of Licensee's implementation of Generic Letter (GL) 96-01 Testing of Safety-Related Logic Circuit b.' ' Observations and Findinos
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The licensee provided its initial response to GL 96-01 in a letter dated April 17,199 This initial response defined the scope of the systems that were included in the review program and the schedules for completing the review and submitting future responses to the NRC. .in a letter dated May 20,1997, the licensee stated: "The review program that was recently completed on Catawba Units 1 and 2 confirmed that all portions of the affected logic circuitry were being tested such that the existing station TS were fulfilled."
Since the time of the licensee's review program, the ficensee has converted to the improved TS and may have implemented some design changes to the circuitry. This l
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- ~ irIspection reviewed the current TS and drawings as well as the drawings used i[the review progra The present surveillance testing of the system actuation circuits reviewed was consistent with GL 96-01 requirements and complied with TS. The engineered safeguards test adequately demonstrated that the turbine driven auxiliary feedwater pump would start on a loss of voltage condition. The inspector independently verified that all portions of the safety-related circuitry were being tested, and that the licensee's program documentation
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demonstrated a thorough review. Testing of the ECCS switch over to the RWST was adequately addressed in the testing associated with TS Table 4.3-2, item 9, Table 4.3-2 Engineered Safeguards Feature (ESF),4.8.1.1.2 (EDG), and 4.5.2.e.1 and included adequate overlap with the end device such as the valve, pump, etc. For the EDG start actuation, the inspectors reviewed the voltage relay circuitry from the protective relay itself through the emergency diesel generator starting air solenoids. The inspectors found that start signal functions were adequately tested via the calibration check, two-out-of-three logic test, and the ESF integrated tes The inspectors noted that the licensee had identified significant problems during their GL 96-01 review and had corrected those problems through the PIP process. For example, the two-out-of-three logic for the voltage relays in the loss-of-voltage EDG start circuit
. was not previously being tested as described by GL 96-01 and therefore was an inadequate surveillance for TS 4.8.1.1.2 (g) (4). This was identified in PIP 0-C96-201 The licensee stated that their immediate corrective action to restore compliance with the TS was to revise and perform the surveillance test procedure incorporating the required logic testing. However, the licensee did not identify the inadequate test as a missed TS
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surveillance and initiate the appropriate report as required by 10 CFR 50.73. GL 96-01 stated that plant surveillance test procedures were to test all portions of logic circuitry to fulfill the TS requirements, consequently, an inadequate surveillance test is a missed surveillance test. Following the inspector's identification of this issue, the licensee documented this problem in PIP 0-C99-3097. The corrective actions for PIP 0-C99-3097 will include a licensee review to determine if other NRC reporting omissions were i included in the PIPS identified during the GL 96-01 review. This Severity LevelIV violation of TS 4.8.1.1.2 (g) (4) is being identified as an NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-413,414/99-05-09:
inadequate TS Surveillance 4.8.1.1.2 (g) (4) Testing for Logic Relays in,the EDG Start Circui i The inspectors noted that the licensee's response to GL 96-01, dated May 20,1997, incorrectly concluded that all portions of the applicable TS logic circuitry were being adequately tested such that existing station TS were fulfilled. The response also characterized test procedure changes to ensure the implementation of TS surveillance
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. requirements as enhancements rather than identified problems with the existing
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surveillance test program. As discussed above, the inspectors identified at least one example i1 which TS logic circuitry was not being adequately tested in accordance with TS. Subsequently the licensee determined that there were five examples of inadequate TS logic circuitry testing which they reported in LER 50-413/99-01 A
- c. - Conclusions Based on a review of three circuits, the inspector concluded that safety-related logic circuits were presently being tested in accordance with Generic Letter 96-01, Testing of Safety-Related Logic Circuit .-
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Th'e inspectors noted that the licensee's response to GL 96-01, dated May 20,1[h7, incorrectly concluded that all portions of the applicable TS logic circuitry were being adequately tested such that existing station TS were fulfille An NCV was identified for inadequate TS surveillance 4.8.1.1.2 (g) (4) testing for logic relays in the EDG start circui E3 Engineering Procedures and Documentation E Revision to the UFSAR Inspection Scope (37551)
The project manager reviewed Revision 7 of the Catawba UFSAR in-office and onsite, and met with licensee personnel on July 29,1999, to discuss various issues. The purpose of the review was to confirm if the changes made in Revision 7 complied with the provisions of Title 10 of the Code of Federal Regulations (10 CFR) Section 50.7 Observations end Findinas By letters dated April 8 and May 24,1999, the licensee submitted Revision 7 to the UFSAR in accordance with 10 CFR 50.71. On June 10,1997, the staff issued an exemption to the licensee. This exemption authorized the licensee to schedule UFSAR revisions to once per fuel cycle based only upon Unit 2 refuel;ng outages. Since the last Unit 2 refucting outage was completed in October 1998, the project manager concluded
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that Revision 7 of the UFSAR was submitted in accordance with the schedule specified by the June 10,1997, exemptio The project manager traced selected changes in Revision 7 to documents in the official NRC records (e.g., amendments to the operating license, staff letters transmitting safety evaluations, annual 10 CFR 50.59 reports submitted by the licensee, licensee letters).
The project manager confirmed that changes conveyed by Revision 7 complied with the change scope specified by 10 CFR 50.7 Revision 7 incorporated summary descriptions of the licensee's actions as a result of various NRC Generic Letters and Bulletins. The licensee's actions in response to these Generic Letters and Bulletins had been previously reviewed and approved by the staf The incorporation of such information in appropriate locations of the UFSAR was consistent with the provision of 10 CFR 50.71(e) regarding "all analyses of new safety issues performed by or on behalf of the licensee at Commission request."
c. . Conclusion
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The project manager concludad that Revision 7 of the Catawba UFSAR complied with the provisions of 10 CFR 50 ' E8 Miscellaneous Engineering issues (92700,92903)
E (Closed) LER 414/98-005-01: Violation of Technical Specification 3.6.5.3 due to inoperable Ice Condenser Lower inlet Doors Caused by Ice / Frost Buildup Restricting Door Movement
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- (Closed) LER 413/99-003-00Niolation of Technical Specifications due to Inoper$ble Ice Condenser Lower Inlet Doors Caused by ice / Frost Buildup Restricting Door Movement These reports involved TS violations that were discussed during a predecisional enforcement conference on July 20,1999. On August 2,1999, these violations were characterized as non-cited violations and are issued in this inspection report as NCV 413,414/99-05-12: Failure to Maintain Ice Condenser inlet Doors Operable (Refer to Section X2). As documented in NRC Inspection Report 50-413,414/99-11, the licensee had planned to inste:I insulation during the Unit 1 refueling outage in the spring of 199 Inspectors obtained and reviewed work order 98132821 to verify that a modification to install insulation on glycol piping had been completed. Inspectors reviewed the Unit 2 modification package and observed the finalinstallation of the beam cooler modifications in the Unit 2 ice condenser, as documented in NRC Inspection Report 50-413,414/98-16, Section E1.2.b.3. Corrective actions were completed, and these items are close E8.2 (Closed) LER 50-414/99-001-(00. 01): Unanalyzed Condition Associated with Relay Failure in the Auxiliary Feedwater (CA) System Due to inadequate Single Failure Analysis Unit 2 CA pump turbine (CAPT) control circuit experienced failure of a relay that resulted in declaring both the turbine driven and the A train motor driven CA pumps inoperable on January 15, and January 29,1999. The failed relay resulted in a loss of control power to the turbine driven pump and impaired the capability to transfer the A train pump source to the assured supply. The licensee later determined that the CAPT was operable due to the availability of its B train actuation logic. A TS action item was entered in both cases and appropriate actions were initiated. uwe investigation and corrective actions were documented in PIPS 2-C99-0199 and 2-CGo-0389. There was limited safety impact since the relay failure was annunciated in the control room and the ability to manually align the assured supply was not impacted by the failur As stated in the licensee's root cause investye6cn in these PlPs, the initial January 15,1999, failure was due to a defect in the relay holding St. Corrective action was to replace the coi The second failure was due to a degraded relay switch which was degraded by the higher current resulting from the initial coil failure. PIP 2-C99-0389 stated that the corrective action for the initial relay failure was inadequate in that it did not replace the en. tire relay nor provide adequate functional testing to assure the relay coil replacement was an adequate relay repai The corrective actions in the second PIP were adequate to assure the relay was adequately repaired and addressed relay functional test procedures to assure adequate testing was performed following relay maintenance. This failure to perform adequate corrective actions following the first relay failure is cowrary to the requirements of 10 CFR 50 Appendix B, Criterion XVI. This Severity Level n/ violation is being treated as an NCV, consistent with
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. Appendix C of the NRC Enforcement Policy. It is identified as the first example of NCV 50-413,414/99-05-06: Inadequate Corrective Actions, Two Examples; CAPT Failed Relay and Control Rocm Chiller Degradation,
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- ~ .w. E8' 3^~ (Closed) insoector Followuo item (IFI) 50-413.414/99-02-01
- Control Room Are(Chiller
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Package Operable-But-Degraded (OBD) Condition and Service Water Pond Temperature impact This item addressed an occurrence on April 11,1999, in which the standby nuclear service water pond (SNSWP) temperature exceeded the temporary limit established by an OBD evaluation documented in Nuclear Site Directive (NSD) Appendix E.203, Operability Notification Form, YC Chiller 1&2, dated January 17,1999. TheIFlwas initiated to review the licensee's actions to address the recurring system seasonal '
bio-fouling problems and determination of the cause of exceeding the OBD established temperature limit. The decreased chiller performance was due to seasonal sediment accumulation and buildup of a bio-film which impacted the heat transfer capability of the heat exchanger tubes. The licensee's methodology for addressing the recurring chiller degradation issue was adequate and includec' periodic monitoring, establishment of bounding temperature limits to assure the system design function, and cleaning when monitored parameters reach a limiting condition. In this case, the corrective actions to establish bounding temperature conditions were not adequately implemented. The actions required a temporary change to the operator aid computer (OAC) set points to alarm at a 70-degree SNSWP temperature and nuclear service water (RN) essential header temperature of 85 degrees. Although the OBD evaluation referenced a minor modification (CNCE-10108) to change the setpoints, the modification was not implemented. An operations procedure was used to char,ge the set points in the OAC; however, the procedure was not totally implemented in that the OAC alarm setpoint for the SNSWP was not changed. The result was that operations was not alerted when the SNSWP temperature of 71.3 degrees exceeded the OBD limiting value of 70 degrees on
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April 11,1999. Subsequent evaluation by engineering determined a higher limiting SNSWP temperature of 77.5 degrees. This failure to perform adequate corrective actions to address control room chiller degradation is contrary to the requirements of 10 CFR 50 Appendix B, Criterion XVI. Captured in the licensee's corrective action program as PlP 0-C99-1265, this Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC Enforcement Policy. It is identified as the second example of NCV 50-413,414/99-05-06: Inadequate Corrective Actions, Two Examples; CAPT Failed Relay and Control Room Chiller Performance Degradatio E8.4 (Closed) LER 50-413/97-009-02: Unanalyzed Postulated Single Failure,Affecting the l Steam Generator Tube Rupture (SGTR) Analysis (Closed) Anoarent Violation (EEI) 50-413.414/99-03 06: inadequate Design implementation of 1987 Generic SGTR Analysis Previously addressed in NRC Inspection Reports 50-413,414/98-11 and
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50-413,414/99-03, the subject LER and associated eel concerned a licensee-identified old design issue in which the previously analyzed limiting case of one stuck open power operated relief valve (PORV) for SGTR accident analysis was determined not to be the limiting case. By letter dated July 1,1999, NRC exercised enforcement discretion (EA i 99-132) by closing the eel and refraining from issuing a Notice of Violation. Revision two of the LER addressed a change in the corrective actions specified in the earlier
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revisions. The related corrective actions were adequately entered into the licensee's corrective action program in PIP C99-167 ..
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kJ%.E8.5' ~ (Closed) LER 50413/99-010-01! Both Catawba Units Operated Outsi Basis and Unit 2 Experienced a Forced Shutdown as a Result of Flow Restriction Caused by Corrosion of the CA System Assured Suction Source Piping Due to inadequate Testing (Closed) LER 50-414/99-002-00: Both Catawba Units Operated Outside Their Design Basis and Unit 2 Experienced a Forced Shutdown as a Result of Flow Restriction Caused by Corrosion of the CA System Assured Suction Source Piping Due to inadequate Testing This item was initially described in LER 50-414/99-002-00. The licensee subsequently determined that this issue was applicable to both units and issued an update as LER 50-413/99-10-0 On May 4,1999, the licensee determined that the CA pumps were inoperable due to the degraded ability of the RN system to provide an adequate assured suction source for the operation of the CA pumps during certain accident scenarios. The performance of a new periodic test procedure, PT1/A/4400/014, RN to CA Suction Piping Flow Measurement, determined that the piping roughness assumed in the design basis calculation CNC-1223.42-00-001, Confirmation of CA System RN Transfer Scheme Adequacy, revision 12C, was exceeded in the installed piping. The assumed piping roughness was 1.6 milli-feet for train 18, which was flow tested. This value varied depending on the specific configuration of the individual train piping. The as-found roughness values were determined to be 12 to 13 milli-feet, which exceeded all assumed value .
The increased roughness and associated decreased piping diameter resulted in a flow restriction that impacted the safety-related assured CA supply source capacity The flow restriction was caused by the long term build up of biological deposits and corrosion in the RN to CA supply piping. In this condition, the assured source would not have been capable of meeting the CA pump flow requirements for accident conditions without reliance on the non-safety related suction sources. Specifically, the accident conditions could result in a high CA pump flow demand for all pumps without adequate nat positive j suction head, resulting in potential pump damage or loss of all CA pumps. The available i non-safety sources included the upper surge tank and main condenser hotwell. The RN j to CA supply piping flow capability was degraded on both trains of each unit. Unit 1 was-shutdown and Unit 2 was in Mode 1 when this condition was identifie The immediate and interim corrective actions, once the condition was identified, were prompt comprehensive, and included: shutdown of Unit 2; mechanical cleaning of piping; modifications to replace the most severely affected piping; and testing to verify
. adequate flow for CA pump operability. These actions, and licensee performance related to issue identification, were previously reviewed by the NRC and documented in
. NRC Report 50-413,414/99-03. Speci'ic allowabin piping roughness values were calculated for each train configuration based on required RN to CA flow and incorporated into acceptance criteria for each RN train. The revised roughness values were 9.1,1.6, 3.0, and 2.0 milli-feet for RN trains 1 A,1B,2A, and 2B, respectively. These were documented in CNC-1223.42-00-001, Revision 13A. Prior to declaring the CA pumps operab e, performance of the new periodic test verified the piping roughness condition was acceptable for each trai ..
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The licensee's failure to identifh the degraded piping condition prior to its impactin a safety related system was an example of inadequate corrective action. The licensee was notified of potential system degradation of raw water systems via NRC Generic Letter 89-13, Service Water System Problems Affecting Safety Related Equipment, dated July 1989, and failed to establish an adequate test program to provide for identification and correction of degraded conditions. Additionally, on September 14, 1998, the licensee identified in PlP C98-3393 that aldough the piping was subject to degradation, the RN system surveillance was not adequate to support CA system design calculation assumptions regarding RN supply piping roughness. The corrective actions for this PIP did not evaluate the condition of the piping. The licensee's root cause documented in PlP C99-1675 was that internal piping monitoring for the RN system was ineffective in identifying the development of increased roughness of the piping. A contributor was the marginal sizing of this portion of the RN piping for worst case flow condition Th'e actual safety significance of the degraded RN/CA supply piping was low. Given that the condensate storage system (CSS) was available, the CA system would have been able to supply sufficient flow to meet accident analysis requirements for reactor coolant system (RCS) heat removal. As the preferred supply source, the CSS volume was adequate to meet RCS cooldown requirements without the use of the safety-related assured supply source. A seismically induced steam line break coincident with a seismic failure of condensate suction sources was the dominant accident scenario for the degraded RN/CA piping condition. The low initiating event frequency for this scenario and the ability to prevent core damage by the independent capability for feed and bleed resulted in low risle significance. In accordance with the Enforcement Policy Section C,
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this Severity Level IV violation of 10 CFR 50, Appendix B, Criterion XVI, is identified as NCV 50-413,414/99-05-07: Inadequate Corrective Action to identify Degraded Service Water Supply Piping to Auxiliary Feedwater Pump The licensee made a one-hour event notification of the Unit 2 forced shutdown required by TS 3.7.5.B. The shutdown was initiated at 4:52 a.m. on May 5,1999. However, the licensee reported the shutdown to the NRC at 12:01 p.m. on May 5,1999, seven hours after the unit shutdown was initiated. According to the licensee, the requirement to submit the report was initially overlooked because of the high number of issues being addressed at the time. This failure to comply with 10 CFR Part 50.72 constituted a violation of NRC requirements. This Severity Level IV violation is being treated as an NCV, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PIP C-99-1675. This item is identified as NCV 414/99-05-08: Failure to Submit NRC Notification in the Time Require IV. Plant Support
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~R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Radioloaical Work Controls a. Inspection Scope (83750) -
The inspectors observed Radiation Protection (RP) activities, comparing them to applicable RP program and 10 CFR Part 20 requirements. The licensee's controls for high radiation areas and very high radiation areas were evaluate .
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- @lo- w."b) Observations and Findinas' "~~ #
Independent radiation surveys made by the inspector were in agreement with licensee's radiation survey results; The radiological postings were adequate for areas surveye The inspectors obtained a list of all extra high radiation areas (EHRA) and very high
. radiation areas (VHRAs), and recent radiation surveys in those areas. The inspectors i verified all high radiation areas were properly secured, and verified that the licensee was maintaining positive control of keys in to EHRAs and VHRAs. All of the locked high radiation doors checked by the inspector were secured properl The inspectors reviewed the licensee's procedures and controls for diving operatione in radiologically controlled areas. The licensee's procedure provided good guidance in the preparations of dives and in the control of divers in the water. Individual occupational radiation worker doses remained low, with the highest exposure categories well below the regulatory limit Conclusions Licensee radiation surveys, postings, access controls, and radiological work controls met regulatory requirements. High radiation areas were properly controlled. Licensee procedures for controlling divers in radiological creas were adequate. All individual personnel radiation exposures were less than regulatory limit R1.2 As Low As Reasonably Achievable (ALARA)
. Insoection Scope (83750)
Performance and implementation of ALARA program for the most recent refueling outage (RFO), Unit 1 End of Cycle (EOC) 11 were evaluate . Observations and Findinas in 1998, the licensee met their non-outage dose goal, but exceeded the annual and 1 outage dose goal ,
in 1999, the licensee set a site record for collective dose (94.5 Person-Rem). This occurred during the most recent Unit 1 EOC 11 RFO. The primary reason for low collective dose in the EOC11 RFO was the effectiveness of the licensee's shutdown chemistry procedure. The outage collective dose was significantly below anticipated dose rates by approximately 20 percent. The licensee made significant efforts to
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optimize RCS cleanup process. Other factors contribubag to the lowest RFO dose goal included improvements in work control scheduling and reassessment of routines, elimination of work scope and unnecessary tasks, and improved worker performance for steam generator workers and shielding crews. The licensee lowered the outage goals twice to account for the elimination of approximately 30 person-rem of work scop In non-outage periods, the site labeling project was accumulating the most collective dose (approximately 300-400 mrem per month). Other non-outage activities generating the most dose were operations and RP surveillance l
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T:Lle.- .w.c.c$' C$nclusions #
Better engineering support, work control planning and coordination, and effective I shutdown chemistry procedures were factors contributing to the site's lowest outage collective radiation dose. The Catawba ALARA program was effective in the continued reduction of the site's collective personnel radiation dos R7 Quality Assurance in RP&C Activities R Documentation and Corrective Actions
. Inspection Scope (83750)
Recent PIPS for the RP Program were reviewed to identify adverso RP trends and specific PIPS were reviewed to verify corrective actions were appropriate and resolve A review of the licensee's audit activities was also mad Observations and Findinos The inspectors reviewed recent .RP issues identified in licensee PIPS. The inspectors determined that the licensee's threshold for placing issues into the corrective action program was appropriate. No significant adverse trends in RP performance were identified. The reviewed PIPS included good analysis of problems with appropriate corrective actions to prevent recurrenc The inspectors also reviewed licensee activities for a RP audit in progress during the inspection. The inspector found the audit scope and checklist adequate. The licensee made good use of staff technical expertise to assist the qualified auditors during the program evaluations. The inspector reviewed audit findings and found important
, technical issues were being identified. The inspector attended the audit exit meeting and observed a good exchange of information concerning identified issue Conclusions
[ The RP personnel were effectively utilizing the corrective action program to make f program improvements and correct identified program deficiencies or non-compliance The licensee's formal audit process using technical resources was an effective tool to improve performance and complianc S1 Conduct of Security and Safeguards Activities
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S1.1 . Protected Area Access Control- Personnel Inspection Scope (81700)
The licensee's program for recording access of personnelinto and out of the protected area r : evaluated against Chapter 5 of the Physical Security Plan and Nuclear Security
. Manual, Protected Area Search / Ingress Process, Revision 6, dated November 2,1998, l
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17 i W.w au .s g . - Observations and Findinas' ' '
The licensee used a computerized hand geometry access system to record access i control data for personnel entering and exiting the protected area (PA). Prior to the inspector's departure, the licensee demonstrated the capability to query the computer and provide a report in chronological order of entries and exits from the PA. Therefore, the PA entry and exit transactions by personnel on specific dates were verifie l Conclusion The licensee met regulatory requirements conceming access of personnelin and out of the facility protected are S3 Security and Safeguards Procedures and Documentation S Security Proaram Plans and Procedures Inspection Scope (81700)
The inspectors reviewed the licensee's Physical Security / Contingency Plan, Revision 9, {
dated April 26,1999, against the provisions of 10 CFR 50.54(p). Observations and Findinas The limited review of Revision 9 to the Physical Security / Contingency Plan, verified the
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licensee's submittal met the requirements of 10 CFR 50.54(p). The Physical Security / Contingency Plan changes, although major, mainlu clarified titles and made grammatical change Conclusion The licensee met the requirements of 10 CFR 50.54(p).
SS Security Safeguards Staff Training and Qualification
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S Security Trainino and Qualification Inspection Scope (81700)
The inspectors reviewed the training and qualifications of individuals assigned security officer or armed responder duties against the NRC-approved Training and Qualifications
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. Plan (TQP). In addition, refresher training for requalified security personnel was evaluated against the TOP specification Observations and Findinas i
Ten training files of currently employed security officers were reviewed to ascertain I whether qualification scores and assigned duties, physical fitness test results, and weapon requalification scores met the requirements of the TOP. The reviewed data reflected accurate record keeping and compliance with the provisions of the TQ I Additionally, the inspectors interviewed four officers to determine their depth of
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m%a w.... ' ~ ' I riowledge of the requiremeiits.~ The officers interviewed and observed in the co'urse of their duty were knowledgeable and cognizant of their assigned responsibilitie Response Canabilities - The inspectors reviewed security response drill documentation and noted that the licensee had a very aggressive drill training program as evidenced by 108 Force-On-Force drills conducted in 1998 and 83 Force-On-Force drills conducted in 1999. The drills were developed using the target sets established and refined by the licensee and the Operational Safeguards Response Evaluation (OSRE). The benchmark for the drills was the NRC design basis threat. The criteria used by the licensee to determine response capability involved whether the security force could:
(1) provide a sufficient number of responders; (2) provide responders appropriately armed; (3) provide responders in protected fighting positions; and (4) provide responders in time to interdict armed intruders. The inspectors noted that the licensee was required by the Physical Security Plan to maintain the same number of trained and qualified armed response officers as used during the OSRE conducted in January 199 On August 18,1999, the inspectors observed the licensee conduct two table top exercises. ' During each exercise, the security force demonstrated the capability to
- implement their defensive strategies to deter the adversary based on the design basis threa Conclusion Security officers were appropriately trained and qualified to perform their duties in accordance with the licensee's TQP. Conduct of contingency drills and implementation
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of defensive strategies were considered security program strength S7 Quality Assurance in Security and Safeguards Activities S Audits /Self Assessment Prooram Insoection Scope (81700)
.The inspectors evaluated the licensee's audit program against the commitments of ,
Chapter 11 of the Physical Security / Contingency Plan. During the inspection, a small j representative sample of problems identified by audits was evaluated to determine whether reviews and analyses were appropriately sssigned, analyzed, and prioritized for corrective action and whether corrective actions were technically adequate and performed in a timely manner, Observations and Findinos
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The licensee's program commitments included auditing the security program at least every 12 months. The audits reviewed routine and contingency security procedures and practices. The reviews evaluated the effectiveness of _the physical protection system testing and maintenance program, access authorization, safeguards contingency plan implementation, training and qualification, central alarm station operation, storage of
' safeguards information, and access control. The inspector reviewed the annual audits SA-97-07 (CN)(RA) Security May 5-8,1997, SA 98 32 (ALL)(RA), January 19 through February 6,1998 and SA-99-01 (CN)(RA), January 18-28,1999. Additionally, the security section had conducted five self-assessments between February 2,1998, and
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V:w .w ,, - F$bruary 2, '1999. The audit' reports concluded that the security program was e[ective and' recommended actions to improve the performance of the security program. The licensee responded appropriately to the audit report recommendations. The audits and self-assessments were thorough, complete, and effective in determining that the security force is capable of meeting the regulatory requirement l Conclusion Licensee-conducted audits were thorough, complete, and effective. Audit findings and recommendations were appropriately reviewed, assigned, analyzed, and prioritized for corrective action. Corrective actions were technically adequate and timely. The audit /self-assessment program is a security program strengt V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on September 7,1999. The licensee acknowledged all the findings presented. No proprietary information was identifie l X2 Escalated Enforcement Results '
On July 20,1999, a predecisional enforcemerit conference regarding EA case number 98-477 was held in the regional office with the licensee in attendance. At this
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. conference, Apparent Violations (Eels) involving inoperability of and degraded conditions associated with the Unit 1 and Unit 2 ice condensers were discussed. The specific items discussed were as follows: {
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eel 50-413/99-11-01 Failure to Maintain Ice Condenser Lower inlet j Doors Operable l eel 50-414/98-16-01 Failure to identify and Correct Ice Basket Deformation eel 50-414/98-16-03 Inadequate Ice Condenser Debris Visual Inspection eel 50-414/98-16-04 Failure to Maintain Ice Condenser inlet Doors Operable eel 50-413/98-13-01 Failure to identify and Correct Significant ice
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Condenser Flow Blockage eel 50413/98-13-03 inadequate Ice Condenser Debris Visual Inspection eel 50-413/98-13-05 Failure to identify and Correct Ice Basket Deformation eel 50-413,414/98-13-07 Failure to Properly install ice Condenser Deck Door Bolting and Hardware
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F eel 50-413,414/98-1'3-08 Inadequate Design Control On August 2,1999, the above Eels were dispositioned as six NCVs. Accordingly, the Eels previously listed are closed and the NCVs will be tracked as follows:
NCV 50-413/ 99-05-10 Failure to identify and Correct Significant Ice Condenser Flow Blockage NCV 50-413,414/99-05-11 Inadequate Ice Condenser Debris Visual inspection NCV 50-413,414/99-05-12 Failure to Maintain Ice Condenser inlet Doors ;
Operable NCV 50-413,414/99-05-13 Failure to identify and Correct Ice Basket Deformation NCV 50-413,414/99-05-14 Failure to Properly Install ice Condenser Deck Door i Bolting and Hardware NCV 50-413,414/99-05-15 Inadequate Design Control I l
PARTIAL LIST OF PERSONS CONTACTED f
l Licensee j
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S. Beagles, Safety Review Group Manager M. Boyle, Radiation Protection Manager S. Bradshaw, Safety Assurance Manager T. Byers, Site Security Manager G. Gilbert, Regulatory Compliance Manager R. Glover, Operations Superintendent j P. Grobusky, Human Resources Manager j P. Herran, Engineering Manager R. Jones, Station Manager ,
R. Parker, Maintenance Superintendent G. Peterson, Catawba Site Vice-President F. Smith, Chemistry Manager INSPECTION PROCEDURES USED
- IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
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Problems IP 61726: Surveillance IP 62707: Maintenance Observation !
IP 71707: Plant Operations l
.lP 81700: Physical Security Program for Power Reactors )
IP 83750: Occupational Radiation Exposure !
IP 92700: Onsite Followup of Written Event Reports i IP 92902: Followup - Maintenance {
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Followup - Engineering'
Tl 2515/139: inspection of Licensee's Implementation of GL 96-01 ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-413/99-05-01 NCV Failure to Follow Procedure Gove. ming AFW Pump Motor Maintenance (Section M1.2)
50-413,414/99-05-02 NCV . Failure to Perform Ice Condenser Lower inlet Plenum and Tuming Vane Inspections per TS Requirements (Section M8.1)
50-413,414/99-05-03 NCV Inadequate ESFAS Procedures Result in Missed TS Surveillance (Section M8.2)
50-413,414/99-05-04 NCV inadequate VX System Test Procedures (Section M8.3)
50-413,414/99-05-05 NCV Missed Turbine Trip - Reactor Trip Testing Required by TS 3.3.1.15 (Section M8.4)
50-413,414/99-05-06 NCV inadequate Corrective Actions, Two Examples:
CAPT Failed Relay and Control Room Chiller
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Degradation (Sections E8.2, E8.3)
50-413,414/99-05-07 NCV inadequate Corrective Action to identify Degraded Service Water Supply Piping to Auxiliary Feedwater Pumps (Section E8.5)
50-414/99-05-08 NCV Failure to Submit NRC Notification in the Time Required (Section E8.5 )
50-413,414/99-05-09 NCV inadequate TS Surveillance 4.8.1.1.2 (g)(4) Testing for Logic Relays in the EDG Start Circuit (Section E1.1)
50-413/99-05-10 NCV Failure to identify and Correct Significant ice Condenser Flow Blockage (Section X2)
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50-413,414/99-05-11 NCV Inadequate Ice Condenser Debris Visual inspection
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(Section X2) ,
50-413,414/99-05-12 NCV Failure to Maintain Ice Condenser inlet Doors Operable (Section X2)
50-413,414/99-05-13 NCV Failure to identify and Correct ice Basket Deformation (Section X2)
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3 5 7 3."50-4'13,414/99-05-1'4 NCV'" Failure to Properly Install Ice Condenser De#ck Door Bolting and Hardware (Section X2)
l 50-413,414/99-05-15 NCV Inadequate Design Control (Section X2) I l
Closed i
50-413/98-015-(00,01) LER Technical Specification Required Shutdown and Operation Prohibited by Technical Specifications Associated with the Ice Condenser (Section M8.1)
98-6-015 NOED Catawba Unit 2 Ice Condenser Flow Passage Inspection (Section M8.1)
50-413/98-018-00 LER inadequate Procedures for ESFAS Response Time Testing Cause Failure to Satisfy TS Requirements (Section M8.2)
50-413,414/99-01-01 URI ESF Response Time Testing for Hydrogen Skimmer (VX) Fan Suction isolation Valves (Section M8.3)
50-413/99-005-00 LER Surveillance Requirements for Turbine Trip-Reactor Trip Functions incorrectly Performed Causing Technical Specification Non-compliance (Section
.
M8.4)
50-413/99-005-01 LER Surveillance Requirements for Turbine Trip -
Reactor Trip Functions In 'rrectly Performed Due ]
'
to Lack of Understanding of Test Requirements .
(Section M8.4)
50-414/98-005-01 LER Violation of Technical Specification 3.6.5.3 due to Inoperable ice Condenser Lower inlet Doors ,
Caused by Ice / Frost Buildup Restricting Door Movement (Section E8.1)
50-413/99-003-00 LER Violation of Technical Specifications due to i Inoperable Ice Condenser Lower Inlet Doors j Caused by Ice / Frost Buildup Restricting Door Movement (Section E8.1) 3
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~ 50-414/99-001-(00, 01) LER Unanalyzed Condition Associated with Relay Failure in the Auxiliary Feedwater (CA) System Due l
to inadequate Single Failure Analysis (Section ;
E8.2)
50-413,414/99-02-01 IFl Control Room Area Chiller Package Operable-But-Degraded Condition and Service Water Pond Temperature impact (Section E8.3)
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W7 au.50413/97-009-02 LER Unanalyzed Postulated Single Failure Affec$ng the SGTR Analysis (Section E8.4)
50-413,414/99-03-06 eel Inadequate Design implementation of 1987 Generic SGTR Analysis (Section E8.4)
50-414/99-010-01 LER Both Catawba Units Operated Outside Their Design Basis and Unit 2 Experienced a Forced Shutdown as a Result of Flow Restriction Caused by Corrosion of the CA System Assured Suction Source Piping Due to inadequate Testing (Section E8.5)
50-414/99-002-00 LER Both Catawba Units Operated Outside Their Design Basis and Unit 2 Experienced a Forced Shutdown as a Result of Flow Restriction Caused by Corrosion of the CA System Assured Suction Source Piping Due to inadequate Testing (Section E8.5)
50-413/99-11-01 eel Failure to Maintain Ice Condenser Lower Inlet Doors Operable (Section X2)
50-414/98-16-01 eel Failure to identify and Correct Ice Basket
.
Deformation (Section X2)
50-414/98-16-03 eel Inadequate Ice Condenser Debris Visual inspection (Section X2)
50-414/98-16-04 eel Failure to Maintain Ice Condenser inlet Doors Operable (Section X2)
50-413/98-13-01 eel Failure to identify and Correct Significant Ice Condenser Flow Blockage (Section X2)
50-413/98-13-03 eel Inadequato Ice Condenser Debris 9isual Inspection (Section X2)
50-41S/98-13-05 eel Failure to identify and Correct Ice Basket Deformation (Section X2)
- - 50-413,414/98-13-07 eel Failure to Properly Install Ice Condenser Deck Door
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Bolting and Hardware (Section X2)
50-413,414/98-13-08 eel inadequale Design Control (Section X2)
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- e % p;g g E 50-413/99-014-00 LER Missed Surveillances and Operation Prohibited by TS Occurred as a Result of Defective Procedures or Programs and inappropriate TS Requirements (Section E1.1)
As Low as Reasonably Achievable ASTM -
American Society for Testing and Materials BB -
Steam Generator Blowdown Recycle System CA -
Auxiliary Feedwater CAPT -
Auxiliary Feedwater Pump Turbine CFR -
Code of Federal Regulations CSS -
Condensate Storage System EA -
Enforcement Action EDG -
Emergency Diesel Generator eel -
Escalated Enforcement item EHRA -
Extra High Radiation Area EOC -
End Of Cycle ESF -
Engineered Safety Features ESFAS -
Engineered Safety Features Actuation System F -
Fahrenheit
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IFl -
Inspector Followup item IP -
Inspection Procedure LCO -
Limiting Conditions for Operations LER -
Licensee Event Report LOCA -
Loss Of Coolant Accident LOOP -
Loss Of Offsite Power NCV -
Non-Cited Violation NOED -
Notice of Enforcement Discretion NRC -
Nuclear Regulatory Commission NSD -
Nuclear Site Directive ~
NSRB -
Nuclear Safety Review Board OAC -
Operator Aid Computer OBD -
Operable-But-Degraded OSRE -
Operational Safeguards Response Evaluation PA -
Protected Area PIP -
Problem Identification Process
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PM . -
Preventive Maintenance
~PORV -
Power Operated Relief Valve RA -
Condenser Tube Cleaning System RCS -
Refueling Outage RN -
Radiation Protection RP&C --
Radiological Protection and Chemistry R Response Time SGTR -
Steam Generator Tube Rupture
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.e
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ta 25
% 'W .3.2,SNSWP -
Standby Nuclear Service Water Pond #
SR -
Surveillance Requirement SSPS -
Solid State Protection System TADOT -
Trip Actuating Device Operational Test TBS -. Turbine Building Sump TEDE -
Total Effective Dose Equivalent TOP, -
' Training and Qualification Plan TS -
Technical Specification UFSAR -
Updated Final Safety Analysis Report URI -
Unresolved item VHRA - Very High Radiation Area VX . -
Hydrogen Skimmer WC -
Conventional Waste Water Treatment WP -
Turbine Room Sump Pump System (powerhouse)
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