IR 05000338/1996007
| ML20134C648 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 09/09/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20134C632 | List: |
| References | |
| 50-338-96-07, 50-338-96-7, 50-339-96-07, 50-339-96-7, NUDOCS 9609270341 | |
| Download: ML20134C648 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
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Docket Nos: 50-338, 50-339 License Nos: NPF-4, NPF-7
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Report Nos: .50-338/96-07,50-339/96-07 Licensee: Virginia Electric and Power Company (VEPC0) :
Facility: North Anna Power Station, Units 1 & 2 Location: 1022 Haley Drive :
Mineral, Virginia 23117 Dates: June 30 through August 10, 1996 Inspectors: R. McWhorter, Senior Resident Inspector D. Taylor, Resident Inspector '
. R. Gibbs, Reactor Inspector (Section M1.1)
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P. Kellogg, Senior Project Manager (Section 02.3)
G. Walton, Reactor Inspector (Section 02.3) !
E. Testa, Senior Radiation Specialist (Sections R1, R2 and R7)
Approved by: G. Belisle, Chief, Reactor Projects Branch 5 Division of Reactor Projects
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9609270341 960909 PDR ADOCK 05000338 O PDR ,-,
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EXECUTIVE SUMMARY North Anna Power Station, Units 1 & 2 NRC Inspection Report Nos. 50-338/96-07, 50-339/96-07 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six week period of resident inspection; in addition, it includes the results of announced inspections by regional specialists.
Operations
- Daily operations were generally conducted in accordance with regulatory requirements and plant procedures. Good equipment material conditions were evident by extended problem-free plant operation (Section 01.1).
- The Unit 1 High Head Safety Injection System was properly aligned and maintained (Section 02.1).
- Control Room annunciator disablements were effectively controlled (Section 02.2).
= The NRC reviewed the depth, breadth, and scope of the licensee's Service Water System Operational Performance Assessment and found these aspects to be thorough and comprehensive. The leadership of the licensee's assessment team was effective (Section 02.3).
= An Unresolved Item was opened for further review of an event in which an operator momentarily left the Unit 2 controls area (Section 04.1).
- Three self-assessment activities were effective in assessing station performance (Section 07).
- High operations standards for controlling reactivity during power transients were considered a strength (Section M1.3).
Maintenance
= Inspection of the licensee's maintenance program, related to the work on the Unit 2, Train B Charging /High-Head Safety Injection Pump, determined that the program was comprehensive and was adequately implemented. No deficiencies in the program or program implementation were observed. l Plant material condition was also assessed as excellent (Section M1.1). )
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- Response to a failed protection system relay ensured that compliance j
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- A turbine valve freedom test was properly completed and equipment performed in accordance with requirements (Section M1.3).
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- Portions of two surveillance activities reviewed adequately demonstrated equipment operability (Section M3.1).
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Use of a temporary alternative compensatory measure for reactor coolant pump oil collection system inoperability was properly evaluated and controlled in accordance with station procedures (Section E2.1).
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A violation was identified, in that, an inadequate maintenance procedure allowed disabling all containment isolation valves in a penetration during an August 1994 maintenance evolution (Section E8.1).
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A non-cited violation was identified for a failure to meet operability requirements for radiation monitors due to seismic qualification deficiencies existing since original plant construction. The licensee displayed good initiative in identifying and correcting the problem (Section E8.2).
Plant Sucoort !
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An unresolved item was identified involving an improper shipment of radioactive waste to a low level radioactive waste repository (Section RI.1).
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A violation was identified for not labeling a container of licensed j material with sufficient information for workers to avoid or minimize exposures (Section R2.2).
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Housekeeping within the Auxiliary Building, radioactive vaste processing storage, and Fuel Handling Building was acceptable (Section R2.2).
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. A violation was identified for allowing a individual to leave the site !
with contaminated clothing (Section R7.1).
. Observed security activities met regulatory requirements. One unresolved item concerning falsification of calibration records for an alcohol analyzer was closed (Sections S1 and S8).
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!Leport Details
Summary of Plant Status Units 1 and 2 operated the entire inspection period at or near full power.
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I. Operations 01 Conduct of Operations (71707)
01.1 Daily Plant Status Reviews The inspectors conducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to approved procedures. i The inspectors attended daily plant status meetings to maintain awareness of overall facility operations and reviewed operator logs to verify operational safety and compliance with Technical Specifications .
(TSs). Instrumentation and safety system lineups were periodically I
reviewed from control room indications to assess operability. Frequent plant tours were conducted to observe equipment status and housekeeping.
Deviation Reports (DRs) were reviewed to assure that potential safety concerns were properly reported and resolved. The inspectors found that daily operations were generally conducted in accordance with regulatory requirements and plant procedares. Good equipment material conditions were also evident by extended problem-free plant operation.
02 Operational Status of Facilities and Equipment 02.1 Safety Iniection System Walkdown (71707)
a. Inspection Scope During the week of July 22, the inspectors walked down portions of the Unit 1 High Head Safety Injection (HHSI) system. The inspectors reviewed system alignments using procedures 1-0P-7.2A, Valve Checkoff -
High Head Safety Injection, revision 17, and 1-0P-8.lA, Val m Checkoff -
Chemical and Volume Control System Auxiliary Building, re, ision 13-P2, as well as, applicable system drawings, TS, and the Updat ed Final Safety Analysis Report (UFSAR). The inspectors also reviewed component labeling and general material conditions. Specific system portions inspected included HHSI pumps 1-CH-P-1A and 1-CH-P-1B, all accessible suction and discharge piping used during safety injection operations, and power supplies.
b. Observations and Findinas
' The inspectors found that all system components were aligned in accordance with applicable procedures and were in good material
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condition. Component labeling was correct except for the label for check valve 1-S1-66 which was not visible outside the valve's lagging.
One minor drawing discrepancy was noted and reported to system l
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engineering for correction- The inspectors noted a few minor
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housekeeping items which were promptly corrected by the licensee. One loose hanger for an emergency light was also identified (DR N-96-1338),
and the inspectors verified that the hanger was promptly repaired.
During the inspection activities, HHSI pump 1-CH-P-lC was removed from service for maintenance. The inspectors verified that tagging associated with the maintenance was correct by reviewing tagging record 1-96-CH-0053 for adequacy against system drawings. Additionally, the inspectors verified that tags were properly installed on plant components.
c. Conclusions The inspectors concluded that the Unit 1 HHSI system was properly aligned and maintained.
02.2 Disabled Annunciator Review (71707)
a. Insoection Scope On July 23, the inspectors reviewed the status of disabled annunciators i to ensure that annunciators were being controlled in accordance with ;
appropriate procedures. '
b. Observations and Findinas '
The inspectors found that annunciator disablement was controlled by Operations Standard 15, Control Room Annunciator Reconfiguring, revision 1. Operations Standard 15 allowed disabling annunciators under ,
certain conditions in order to maintain a " black board." Annunciators I were allowed to be disabled if they provided no useful information to '
the operator and were caused by a condition not correctable by I maintenance or were caused by the equipment being out of service.
Additionally, the standard did not allow disabling annunciators associated with a TS Limiting Condition for Operation. Several methods !
were allowed for controlling annunciator disabling including temporary modifications, tag-outs, and specifying disablement by procedures.
The inspectors obtained disabled annunciator lists and found that on both units' control panels A through Q, a total of eight annunciators were disabled. The inspectors verified that the disabled annunciators met the above conditions and were appropriately controlled. Six disabled annunciators were specified to be disabled by procedures for out of service equipment, one was disabled under a tagout, and one was disabled by a temporary modification. Additionally, the inspectors observed the patch cord panel used for annunciator disablement and verified that no additional annunciators were disabled. The licensee's automated Annunciator Response Procedures (ARPs) also alerted operators that annunciators were disabled if operators attempted to access an ARP for a disabled annunciator. The inspectors verified that the automated ARPs gave alerts for all the disabled annunciators.
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c. Conclusions i The inspectors concluded that the licensee had an effective program for l controlling disabled annunciators.
02.3 SW Self-Assessment Review ITemporary Instruction (TI) 2515/1181 a. Inspection Scope During the week of July 29, an inspection was conducted to assess the licensee's Service Water System Operational Performance Assessment (SWSOPA) self-assessment report dated September 23, 1994, against TI 2515/118, Service Water System Operational Performance Inspection (SWSOPI). The licensee had requested and the NRC concurred on November 25, 1994, that the scope of the NRC's SWSOPI would be reduced based upon the completion of a SWSOPA. In order to follow up on the licensee's self-assessment during this inspection, field inspections were performed of the complete Service Water (SW) System, and 29 SWSOPA recommendations were reviewed to determine if these activities were conducted in accordance with TS, the UFSAR, approved procedures, NRC Generic Letter 89-13, and appropriate industry codes and standards. In addition to verification that SWSOPA recommendations were addressed, the inspectors
! reviewed the qualifications of the assessment team, and interviewed the SWSOPA team leader and one team member. The following SWSOPA
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recommendations were reviewed:
004.4 010.0 010.1 011.0 012.0 013.0 ;
j 013.1 017.1 034.0 035.0 045.1 048.1 l 049.0 055.0 064.1 067.0 071.0 072.0
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073.0 076.0 081.0 086.0 090.0 094.1 099.0 111.0 119.0 132.0 152.0 ') 1 Listed below is detailed information for the more significant items from J this review. l
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Recommendation 011.0 This recommendation was to evaluate development of a new corrosion coupon procedure for the SW System. The inspectors reviewed corrosion coupon replacement procedure 0-MPM-1907-01, Removal and Installation of Service Water Corrosion Monitoring Coupons, revision 0. This procedure ,
was issued to perform the required maintenance task and was effective ;
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Recommendation 013.0
- This recommendation was to revise the Inservice Test (IST) program for
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Recirculation Spray Heat Exchanger (RSHX) check valves so that it !
reflects that the valves open to provide flowpaths for cooling water to the RSHXs. The inspectors reviewed the IST Program basis that was revised to indicate that the valves were designed to open to provide '
flow to the RSHXs and had no safety function to close. This change was i
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issued in revision 2, dated December 13, 1994, to Section 6.20 of the IST program.
Recommendation 013.1
1 This recommendation was to initiate a UFSAR change to delete reference to check valves being required to isolate a ruptured recirculation spray )
header. There are two redundant separately powered Motor Operated '
Valves (MOVs) in the cross-ties that would be closed to isolate the i ruptured header. The change also closed one Auxiliary Feedwater supply valve to allow header isolation in the event of rupture. An additional isolation valve is open. The reason for the closure was due to the radiation values in the areas of the valves, and the timing in the accident sequence. The inspectors reviewed Change Request to UFSAR Chapter 9.2.1.3.2 dated July 14, 1995. The change was contained in revision 30 dated April 1996.
Recommendation 035.0 This recommendation was to evaluate the need to test relay IX-1SW5N08 since its failure could challenge an entire train of safety systems.
A failure of the IX-ISW5N08 relay followed by an undervoltage on the IH bus could cause the simultaneous starting of SW pumps 1-SW-P-1A and 1-SW-P-4. However, the single failure criteria bounds this scenario and the remaining redundant power train is unaffected by this failure.
Procedures 1/2-PT-36.20, Documentation of Functional Test of Close Interlock From Breaker 15H4 to Breaker 15H5, revision 0, and 1/2-PT-36.19, Documentation of Functional Test of Close Interlock From Breaker 15H5 to Breaker 15H4, revision 0, test the IX relay every 18 months.
Recommendation 045.1 This recommendation was to evaluate the SW reservoir spray efficiency to ensure that it is above 20 percent for all cases. For all cases analyzed (1140 cases), the spray efficiencies were greater than 20 percent. The minimum being 27 percent when the most rigorous model is used. Therefore, the assumption of 20 percent is conservative for the reservoir model.
Recommendation 067.0 This recommendation was to evaluate calculations related to the M0V program acceptance criteria. The MOV torque values were derived by utilizing the "KYPIPE" model and the actual system flow characteristics, rather than the worst case design conditions assumed by the SWSOPA team.
The method using actual characteristics would provide the correct values for the MOV calculations. The justification for utilizing these values is contained in an engineering letter dated June 22, 1995.
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Recommendation 071.0 l
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- This recommendation was to resolve an apparent discrepancy between the
. Environmental Qualification zone source terms and the source terms used for the shielding calculations for the RSHX Radiation Monitors (RMs). l The potential background radiation levels in the monitor cubicles after j a Design Basis Accident (DBA) would saturate the monitors' detectors. l
- This occurs when the Low Pressure Safety Injection pumps are put in recirculation. Design Change Package (DCP) 80-S33 modified the detector J
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the radiation levels to less than 28 mrem /hr which is the cut off point l for sensitivity of the monitors.
l Recommendation 076.0 l
This recommendation was to revise procedure 1/2-PT-75.4, Service Water Screen Wash Pump (1-SW-P-2), revision 8, to include clear acceptance criteria for the inspection of the traveling screens for erosion and corrosion. The inspection of the traveling screens, now in procedure 0-MPM-1906-01, Inspection of Service Water Traveling Screens, revision 1, included appropriate criteria.
Recommendation 081.0 This item identified that if credit is taken for isolating SW to the RSHXs during the course of a DBA, procedures should be revised to include directions for these actions. The licensee's followup on other SWSOPA items recently identified that the SW pumps as installed required a significant higher Net Positive Suction Head (NPSH) than the original design value. The intermediate fix was to require operations to isolate two Recirculation Spray Heat Exchangers (RSHXs) during an accident i condition. This intermediate fix required Emergency Operating Procedure 1 (EOP) changes which were issued on February 23, 1996. The final fix will be to replace the SW pumps with new modified pumps. This is scheduled to be accomplished during 1996 and 1997.
The inspectors reviewed Justification for Continued Operation (JCO)
95-03 titled, " Evaluation of SW Pump NPSH." This JC0 dealt with the pump manufacturer report that the SW pumps as installed had a higher NPSH requirement than the original design considered. This was identified when a new pump was tested in November 1995. The JC0 called for isolation of two RSHXs following a DBA. The E0Ps had been revised to perform this action. This prevented runout of the SW pumps and attendant long term degradation. The pumps are currently being replaced with the same type of pump with the impellers reversed, which solves the 4 NPSH problem. c Recommendation 090.0 l
This recommendation was to review the operation of the cathodic protection system and any effects of new protective coatings on affected
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SW piping. The evaluation of the operation of the cathodic protection system on the SW System is currently scheduled to be completed by August 30, 1996, and the revised Preventive Maintenance (PM) procedure will be issued following the vendor evaluation of the system.
Recommendation 094.1
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Based on this recommendation, the licensee had revised procedures
, 0-AP-39.1, Turbine Building Flooding, and 0-AP-39.2, Auxiliary Building
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Flooding, on December 15, 1994, to incorporate potential flooding from the Turbine Building and Auxiliary Building. The inspectors reviewed these procedures and verified the flooding recommendations had been incorporated.
Recommendation 111.0 This recommendation was to establish a PM program for the Instrument Air
, (IA) compressor Heat Exchanger (HX). The licensee had issued a new PM procedure 0-MPM-0808-01, Preventive Maintenance for Bell and Gosset l'
Model CHXS Heat Exchangers, revision 0, to inspect and clean the IA compressor HX every three years. The PM was issued October 27, 1994.
Recommendation 119.0 This recommendation was to create a PM to inspect the RSHX heat
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exchanger tube sides every other refueling outage. The inspectors reviewed the April 10, 1995, boroscope inspection results and compared
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was an effective method of keeping them clean.
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Additionally, the inspectors reviewed procedure 0-PT-75.15, Generic l Letter 89-13 Service Water System Testing Requirements Coordination, revision 2, that was completed on August 14, 1995. The findings were acceptable. The values for minimum wall thickness identified in the
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procedure were questioned by the inspectors. The numbers appeared to be i
the amount that can be lost in a cycle as opposed to the minimum wall thickness allowed. No areas were found that exceeded the minimum wall l
thickness. The inspectors reviewed PM revisions to procedures 0-MCM-0801-01, Cleaning, Removal and Plugging of Component Cooling Heat l Exchanger Tubes, and 0-MPM-0103-01, Preventive Maintenance of
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Charging /High Head Safety Injection Pumps, to verify mark-ups were incorporated.
Recommendation 152.0
, This recommendation concerned the fouling of SW relief valves with corrosion products and silt causing the setpoints to drift high or low.
VThis has occurred 16 times in the life of the plant; 8 on each unit.
The valves are to be tested during the 1996 outage, and the results of the testing rolled into nuclear Level 1 project 96-013-1, Implement the Long Term Strategy to Resolve Safety and Relief Valve Problems, to l *
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address relief valve problems. This item is currently being tracked under Mechanical Commitment Tracking 96-0060.
b. Observations And Findinas The licensee's team inspection's conclusion were that the North Anna SW System would perform its required functions during a DBA and the requirements of Generic Letter 89-13 had been implemented. :
Additionally, the team recommended that improvements were needed in the ,
maintenance and inspection of some SW components to ensure long term *
system reliability, serviceability, and to maintain the system in a continuing functional condition. The inspectors concluded that the licensee's inspection was thorough, comprehensive, and adequate. The team composition exceeded the minimum standards set forth in TI 2515/118. The inspector's interview of the team leader found that he was persistent and effective in assuring that questions were understood and that answers received by the team were adequate. All 29 items reviewed by the inspectors were found acceptable. All procedures reviewed were found adequate. The corrective actions reviewed were complete and adequate. The inspectors noted the Commitment Tracking System allowed closure of an item before implementation was complete when it was passed to another department for action. While there were no instances identified during this inspection where commitments were lost or not implemented, the potential for the corrective action not being accomplished exists.
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The NRC. review of the licensee's SWSOPA found the licensee's team 1 inspection to be thorough and comprehensive and conclusions reached i regarding the adequacy of the functions of the SW System to be adequate. l Documentation of the results were adequate. The NRC also concluded that i leadership of the licensee's assessment team was effective.
02.4 NRC Notification (71707)
The inspectors reviewed the following licensee notification to the NRC to ascertain if the required report was adequate, timely and proper for the event. On July 30, the NRC was notified as required by 10 CFR 50.72 :
concerning a loss of emergency assessment capability lasting greater )
than one hour. At 11:35 p.m. on July 29, the data link between the Local Emergency Operations Facility and the Safety Parameter Display System (SPDS) was lost during a thunderstorm. At 5:18 a.m. on July 30, the data link between the Corporate Emergency Operations Facility (CEOF)
and the SPDS was also lost due to an equipment problem. Both SPDS links to off site emergency facilities were inoperable until the link to the CEOF was restored at 6:53 a.m. on July 30. The inspectors monitored the licensee's actions and found them to be appropriate.
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04 Operator Knowledge and Performance (71707)
04.1 Operator Presence at the Controls Review On August 5, the inspectors were informed by licensee managers that a
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licensed operator had inadvertently left the Unit 2 controls area for a
! short time period. The fact that no licensed operator was present at the Unit 2 controls was contrary to 10 CFR 50.54k requirements. At the inspection period's end, the inspectors were continuing to review this issue's significance. Until this review is completed, this issue is identified as Unresolved Item (URI) 50-339/96007-01 (EA 96-292): Review Compliance with 10 CFR 50.54k Requirements For Operator Presence at Unit Controls.
07 Quality Assurance in Operations (40500)
07.1 Manaaement Safety Review Committee (MSRC) Meetina
- On July 17, the inspectors attended a regularly scheduled MSRC meeting i at the North Anna site, and observed Station Manager plant status reports and routine subcommittee reports. The inspectors found that the MSRC meeting met TS 6.5.2 requirements for member composition and quorum and that the agenda appropriately included review items required by .
l TS 6.5.2.7. The inspectors observed that the Station Manager reports i
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generated significant self-critical discussions of station performance.
The inspectors concluded that the MSRC was meeting in compliance with i TS requirements and that substantive assessment issues were being l
addressed in the discussions.
07.2 Oversiaht Meetina I On July 25 and on several other occasions during the inspection period, l the inspectors met with Oversight personnel. Issues discussed included Oversight activities and findings since previous meetings. Copies of recent audits were provided for review. The inspectors concluded that the Oversight organization was effectively assessing station performance.
07.3 Station Performance Annunciators Review On July 23, the inspectors observed a Management Review Board meeting where the results of the licensee's second quarter station annunciator l windows were presented to managers. The inspectors found that the licensee was effective in consolidating positive and negative indicators into an overall station performance assessment for the quarter. The inspectors concluded that the station annunciators continued to be a
positive station self-assessment activity, i
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II. Maintenance l M1 Conduct of Maintenance ;
I M1.1 Preventive Maintenance (62700)
a. Inspection Scope During the week of July 8, an inspection was conducted to assess maintenance program implementation. In order to accomplish this effort, ;
inspection of the work and testing associated with an outage on the 1 Unit 2, Train B Charging /HHSI Pump (2-CH-P-18) was conducted. The I inspection included observation of both the electrical and mechanical :
work associated with the pump outage and review of the completed work and testing documentation. The inspection included observation of l procedure adherence, recording and acceptance of technical data by !
maintenance personnel, verification that proper materials (lubricants) l were used, verification of the proper use of calibrated equipment, and i assessment of the adequacy of Post Maintenance Testing (PMT). In !
addition, a review of DRs associated with the work was completed. The '
inspectors also reviewed section 6.3 of the UFSAR for any inconsistencies in information related to this work. Upon completion of ,
this work, the inspectors also conducted an extensive plant tour to j assess overall plant material condition. The following specific components, Work Orders (W0s), DRs, and procedures were included in the inspection: (Items identified with an asterisk were inspected for documentation only.)
Check Valve 2-SW-597, WO 331072-01 Check Valve 2-SW-598, WO 331075-01 Procedure 0-MCM-0432-02, revision 3, Velan Lift Check Valve Repair Check Valve 2-SW-608, WO 331074-01 Check Valve 2-SW-609, W0 331073-01 '
Procedure 0-MCM-0400-32, Disassembly, Inspection, and Reassembly of Check Valves in General, revision 1
- WO 333549-01, Adjust Lube Oil Pressure
- W0 335991-01, Torque Casing Foot Bolts WO 341656-01, Clean Filters /SW Coolers / Sample Oil W0 334104-01, Change Oil in Pump / Speed Increaser Procedure 0-MPM-0103-01, Preventive Maintenance of Charging /High-Head Safety Injection Pumps, revision 5
- WO 341161-01, Change Oil in Both Motor Bearings
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- WO 324135-01, 2-EE-BKR-2H1-2N-F3-CKTBRK l Procedure 0-EPM-0304-01, Testing Non-containment-Isolation 480 Volt Breaker Assemblies, revision 16
W0 341594-01, Procedure 2-EPM-R-1817-02, Protective Relay Maintenance for Breaker 25J6, Charging Pump 2-CH-P-1B, revision 1
- 2-PT-212.26, Valve Inservice Inspection for SW Supply Check Valves to 2-CH-P-1B Lube Oil, Seal, and Gear Box Coolers, revision 5
- 2-PT-213.28, Valve Inservice Inspection (Charging Pump), revision 4
- 2-PT-14.2, Charging Pump 2-CH-P-18, revision 25 DRs:
N-96-1261, Excessive Foreign Material in Check Valve 2-SW-609 N-96-1274, Incorrect Documentation of Torque Applied to Body to Bonnet Fasteners for Check Valves 2-SW-608 and 2-SW-609
- N-96-1266, High Vibrations on 2-CH-P-1B b. Observations and Findinas Inspection of the work and testing associated with the Unit 2, Train B Charging /HHSI Pump determined that the maintenance program had been effectively implemented. Maintenance personnel were knowledgeable of ;
plant procedures and equipment and conducted the work in a very '
professional manner. Work was conducted in accordance with plant procedures, and no deficiencies in the work or documentation of the work were observed. The PMT was technically sound and adequately retested the equipment to establish confidence in the operability of the equipment. No deficiencies were noted during the UFSAR review. Plant material condition was excellent.
c. Conclusions The licensee's maintenance program related to the work on the Unit 2, Train B Charging /HHS1 Pump was found to be comprehensive and was adequately implemented. No deficiencies in the program or implementation of the program were observed. Plant material condition was excellent.
M1.2 Response to Dearaded Voltaae Relav Failure (62703)
a. Inspection Scope On July 11, the inspectors reviewed the licensee's initial responses to an emergency power supply relay failure during testing and verified that proper actions were taken in response to the failure. During the performance of 2-PT-36.11H, Degraded Voltage / Loss of Voltage Functional and Engineered Safety Feature Response Time Test: 2H Bus, revision 7, technicians identified that the 2H bus B phase degraded voltage relay l
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(27XB-2H1) failed to actuate which rendered the channel inoperable. For operation to continue, TS 3.3.2.1 Action Statement 19 required that the channel be placed in the tripped condition within one hour.
b. Observat;ons and Findinas The inspectors were promptly informed of the failure by the licensee and responded to the failed relay's location to verify that the channel was being properly placed in the tripped condition. The inspectors observed that technicians used procedure 2-ECM-2802-01, 2H Emergency Bus Phases A, B, and C Degraded Voltage and Undervoltage, revision 0, section 6.3, to place the channel in trip. The technicians complied with procedural requirements and used proper two-person work techniques when installing the required jumpers in the protective relay racks. The work was completed, and the channel was successfully placed in trip within the one hour TS requirement. Additionally, the inspectors compared 2-ECM-2802-01 procedural steps with system drawing 12050-FE-21T-22 and verified that the jumpers were installed in the correct locations to place the channel in the tripped condition. The relay was replaced and successfully retested later the same day.
c. Conclusions The inspectors concluded that the response to the failed relay was correct and ensured that compliance with TS requirements was maintained throughout the problem.
M1.3 J_urbine Valve Freedom Test (61726. 71707)
a. Inspection Scone On July 12, the inspectors observed operators performing 1-PT-34.3, Turbine Valve Freedom Test, revision 9. The test was performed to meet TS Surveillance Requirement 4.7.1.7.2.a. A slight unit power reduction was required for test performance, and while operating at the reduced power, Main Feedwater Pumps (MFPs) were swapped. During the power transient, the inspectors also reviewed operator controls for reactivity manipulations.
b. Observations and Findinas The inspectors observed that the power reduction was performed using 1-0P-2.2, Unit Power Operation from Mode 1 to Mode 2, revision 35, and the MFP swap was performed using 1-0P-31.1, Main Feedwater System, revision 21. The inspectors found that all evolutions were performed carefully and in accordance with the applicable procedures. Senior Reactor Operator (SRO) oversight of operators performing the evolution was appropriate, and Reactor Operators were observed to use careful self-check practices prior to all equipment manipulations.
Additionally, test performance was found to be consistent with UFSAR section 10.2 turbine test descriptions.
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During the evolution, the inspectors observed that operators had been !
provided a summary of analyses performed by reactor engineers for the evolution.. The summary contained such information as expected rod worths and positions, anticipated xenon and Axial Flux Difference (AFD) ,
transients, and recommended rod manipulations to counter expected !
transient offects. Additionally, the summary reminded operators of rod insertion and AFD limits applicable at the expected transient power levels. The inspectors inquired concerning the reasons for providing the summary to operators and were informed that the summary had been first used in early 1996 to support transients late in core life. The ;
practice had continued, and the summary had become more detailed as '
operators identified that the information enhanced reactivity control during power transients.
The inspectors reviewed Operations Standard number 45, Reactivity Management, dated March 20, 1996. The standing order provided .
guidelines for crew involvement / interaction during reactivity
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manipulations. Guidelines included SR0 acknowledgement for all blender operations, communications standards for moving rods or changing turbine loads, and standards for monitoring the effects of reactivity changes. l The inspectors observed during the evolution that operators followed the l guidance contained in the standing order. As a result, reactivity i manipulations (rod movements, turbine load changes, and feedwater j manipulations) were carefully controlled with excellent communications i between control room operators. j c. Conclusions The inspectors concluded that the test was properly completed and all equipment performed in accordance with TS requirements. The inspectors also concluded that high operations standards and practices for controlling reactivity during power transients were a strength.
M3 Maintenance Procedures and Documentation (61726) !
M3.1 Surveillance Procedure Adeauacy Reviews a. Insoection Scope The inspectors reviewed two concerns identified during routine plant 4 tours to verify that surveillance activities adequately ensured TS-required equipment operability. )
b. Observations and Findinas On July 30, the inspectors observed that Emergency Diesel Generator (EDG) room temperatures were greater that 100*F. The inspectors questioned the impact that such elevated temperatures might have upon the EDG battery banks located in the same room. Specifically, the inspectors were concerned that the temperatures might impact the ability of the EDG battery banks to meet TS 4.8.1.1.3 surveillance requirements for capacity. The inspectors reviewed surveillance records for weekly
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temperature checks and found that pilot cell temperatures varied from f near 50*F in winter to near 100*F in summer. The inspectors discussed the effects the extreme temperatures might have on battery operation i with engineers and reviewed applicable information in the vendor's technical manual. The engineers stated that the high temperatures would reduce battery life, while the low temperatures would reduce battery capacity. Because of the high temperatures, the battery was planned for '
early replacement after approximately ten years life. The engineers
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- sizing took the low temperature effects into consideration down to
- 20.4'F. The inspectors were provided with copies of the design documents and verified that this was correct. ;
On August 1, the inspectors observed that two gas cylinders connected to l
piping used for Unit I hydrogen analyzer calibrations had labels ;
denoting their contents as 0.90 percent (1-GN-TK-29) and 9.80 percent '
hydrogen (1-GN-TK-30). The inspectors noted that this did not appear to match TS 4.6.4.1 requirements for the use of 1 1 0.25 percent and 4 i 0.25 percent. hydrogen for. calibrations. The inspectors brought this ,
i inconsistency to the attention of Instrumentation and Controls j supervisors. The supervisors informed the inspectors that procedure :
ICP-HC-1-H2A-101, Containment Hydrogen System Reactor Containment '
Hydrogen Analyzer, revision 9, actually required the use of three calibration gasses of approximately one, four and ten percent. The two .
Unit 1 gas bottles were used for the one and ten percent' tests, and a i Unit 2 gas bottle was temporarily connected to Unit 1 piping for the four percent test. The inspectors obtained a copy of the most recent test performed on July 25, 1996, and verified that the cylinder number recorded in the procedure for the four percent test matched the cylinder installed on Unit 2 as 2-GN-TK-ll. Additionally, the inspectors i verified that the label attached to that cylinder denoted the contents i as 4.15 percent hydrogen, which met the TS requirements.
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The inspectors concluded that the portions of surveillance activities reviewed adequately demonstrated equipment operability.
III. Encineerina E2 Engineering Support of Facilities and Equipment
! E2.1 Reactor Coolant Pumo Oil Collection System Inoperability (37551. 71750)
a. Inspection Scope On July 6, Unit 2 operators received an Reactor Coolant Pump (RCP) low oil level alarm for pump 2-RC-P-1A. The inspectors reviewed subsequent evaluations performed by engineers to ensure that regulatory requirements were met.
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l b. Observations and Findinas 1 The inspectors found that a containment entry was made shortly after j receiving the alarm, and the oil level was confirmed to be slightly low with no gross leakage problems in the area of the pump. A subsequent entry on the next day found that there was no noticeable further decrease in the pump oil reservoir level. ARPs at the time of the alarm specifically precluded adding more than 1.855 gallons of oil to the RCP.
The oil addition limit was based on the RCP oil collection system's ability to catch and hold the complete volume of oil present in the RCP as required by its 10 CFR 50 Appendix R design bases. Based on the containment entries, maintenance personnel calculated that approximately ten gallons of oil were needed to clear the alarm. Since the oil amount needed exceeded the amount allowed to be added by the oil collection system design basis, engineering assistance was requested to help i resolve the problem. Draining the RCP oil collection system was not desirable due to extremely high radiation levels in the area of the system. The inspectors found that all the initial operations and maintenance personnel responses to the problem were appropriate.
The inspectors reviewed the actions taken by engineering personnel to assist with the problem's resolution. On July 9, the inspectors attended a Station Nuclear Safety and Operating Committee'(SNSOC)
meeting where engineers presented Engineering Transmittal (ET) SE-96-043 and Safety Evaluation (SE) 96-SE-0T-30 with proposed corrective actions.
The proposed actions included declaring the oil collection system inoperable, adding up to 20 gallons of oil, and providing temporary alternative compensatory measures to those contained in the Technical Requirements Manual (TRM) for the extended time that the oil collection system would then remain inoperable. The compensatory measures were proposed to be changed from providing an alternative oil collection arrangement and obtaining NRC exemption approval to monitoring containment and RCP temperatures, stationing fire fighting foam near the containment personnel hatch, and restoring the oil collection system at i the next suitable outage. Additionally, the SNSOC was asked to approve i ARP changes and supplemental work instructions to support the oil !
addition. Except for the approach of providing temporary alternative 1 compensatory measures, the inspectors found that all documents were l properly prepared and supported by analyses and that the SNSOC i appropriately reviewed the involved issues prior to approval.
Following the July 9 SNS0C meeting, the inspectors reviewed the approach j taken to provide temporary alternative compensatory measures in l
! substitution for those contained in the TRM. The inspectors reviewed l 10 CFR 50 Appendix R and the North Anna 10 CFR 50 Appendix R Report and found that both documents provided detailed design requirements for the .
oil collection system. However, neither addressed compensatory actions I to be taken for oil collection system inoperability. The inspectors l then reviewed the history of compensatory action requirements. The )
inspectors found that some fire protection compensatory action i requirements were contained in the original facility TSs, but were relocated to the UFSAR in 1990 in response to NRC Generic Letters 86-10
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and 88-12. During this relocation, Appendix R system operability requirements were added by the licensee to the UFSAR along with compensatory actions. Also at that time, license conditions were added stating that the licensee shall implement and maintain the approved fire protection program and that the licensee may make changes without Commission approval if those changes would not adversely affect the ;
ability to achieve and maintain safe shutdown in the event of a fire. !
The licensee later moved the compensatory action requirements from the
- UFSAR to the TRM using precedence set by NRC approval of similar relocations in areas such as response time limits for reactor protection
- and engineered safety features actuation systems.
The inspectors then reviewed the controls over TRM changes and fire protection program changes. The inspectors found that changes were -
1 controlled by VPAP-2807, Technical Requirements Manual Maintenance, revision 0, and VPAP-2401, Fire Protection Program, revision 1. In this
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case, engineers had not proposed a change to the TRM under VPAP-2807, but rather had proposed temporary alternative compensatory measures as allowed by VPAP-2401. The inspectors reviewed VPAP-2401 and found that
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section 6.7.7 provided requirements for changing TRM compensatory measures without processing a permanent TRM change. The requirements included document preparation by a fire protection engineer, including the changes as a part of a retrievable document, and establishing a time limit for the change. The inspectors verified that these VPAP-2401 requirements were met for the compensatory action change. The
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inspectors also reviewed the ET and SE and concluded that-the licensee had complied with license conditions by considering all factors necessary to ensure that the change did not adversely affect the ability
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to achieve and maintain safe shutdown in the event of a fire, i Additionally, on several different dates throughout the inspection
< period, the inspectors verified that the alternative enmpensatory measures to monitor RCP and containment temperatures were being properly performed by operators. The inspectors found that a special log was kept by operators who reviewed containment and RCP temperatures hourly for adverse trends.
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c. Conclusions The inspectors concluded that the use of a temporary alternative compensatory measure for RCP oil collection system inoperability was properly evaluated and controlled in accordance with station procedures.
E7 Quality Assurance in Engineering Activities E7.1 Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compared plant practices, procedures and/or parameters to the UFSAR descriptions. While performing the inspections discussed in this report, the inspectors reviewed the applicable
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i portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters.
E8 Miscellaneous Engineering Issues (92903, 92700) i a
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E8.1 (Closed) URI 50-338/94019-02: Review TS 3.6.3.1 Applicability to Closed
- System Containment Isolation Valves (CIVs).
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a. InsDection Scope This item concerned the licensee's compliance with TS 3.6.3.1 for a situation encountered on August 2, 1994, during maintenance on 1-CC-TV-103B, a component cooling water return CIV from the residual heat removal heat exchanger. The valve was the only automatic CIV on a line which served a system closed to containment atmosphere in accordance with general design criteria 57. During maintenance to replace the valve's Solenoid Operated Valve (S0V), the valve was blocked open by a temporary modification which routed air around the S0V to the
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valve operator in order to prevent the valve from closing. The .
modification was controlled under 1-M0P-51.03, Installation and Removal '
of N2 or Air Rig for RHR Hx CC Valve Actuators, revision 0-Pl. The TS 3.6.3.1 action statement stated that with one or more of the isolation valves inoperable, maintain at least one isolation valve operable in each affected penetration. A SE completed for procedure 1-M0P-51.03 stated that TS 3.6.3.1 compliance for maintaining an operable isolation valve was maintained by taking credit for the closed system piping boundary. The inspectors questioned whether this interpretation was correct, and referred the-issue to the Office of Nuclear Reactor Regulation (NRR) for review. During this inspection period, the review's results were provided by NRR (Task Interface Agreement 94-031) and the inspectors reviewed this item for closure.
b. Observations and Findinas The NRR review disagreed with the licensee's position concerning TS applicability for CIV operability. Although taking credit for the closed system as a second isolation barrier was consistent with NUREG-1431, Improved Technical Specifications, it was not in compliance with the current North Anna TS 3.6.3.1. Specifically, North Anna Unit I !
TS 3.6.3.1 required that a containment isolation valve be maintained '
operable. If one isolation valve was inoperable and there was no second containment isolation valve, the licensee could not comply with TS 3.6.3.1 requirements and must then have entered TS 3.0.3 and complied with its required actions. The inspectors reviewed activities on August 2, 1994, in light of this guidance. The inspectors found that on that date, the valve was declared inoperable at 2:21 p.m. and physically disabled at 2:33 p.m. The valve was physically restored at 4:07 p.m.
and returned to operable status at 6:10 p.m. Since, during these times, there was no other operable CIV for the penetration, TS 3.6.3.1 could i not be complied with. l l
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10 CFR 50, Appendix B, Criterion V, and the licensee's Quality Assurance Program (UFSAR Chapter 17, Quality Assurance, Section 17.2.5, Instructions, Procedures and Drawings) collectively require that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. TS 3.6.3.1 requires that one isolation valve be maintained operable in each containment penetration. Contrary to these requirements, on August 2, 1994, an inadequate maintenance procedure was used to control maintenance activities affecting quality. Specifically, procedure 1-M0P-51.03 was inadequate, in that, it was used to control maintenance activities which disabled all isolation valves for a Unit I containment penetration for slightly less than four hours. This is identified as Violation (VIO) EA 96-278 01014: Inadequate Maintenance Procedure Causing CIV Inoperability.
c. Conclusions A violation was identified in that an inadequate maintenance procedure allowed disabling all CIVs at a penetration.
E8.2 (Closed) Licensee Event Recort (LER) 50-338. 339/96004: Seismic Concerns Regarding the Containment Particulate and Gaseous Monitors a. Inspection Scope i
This item concerned the licensee's identification on June 11, 1996, that I containment RMs may not have been capable of functioning following a i seismic event as required by the bases for TS 3.4.6.1 which referenced NRC Regulatory Guide 1.45, May 1973. The inspectors reviewed the LER to l ensure that regulatory requirements were met. l b. Observations and Findinas The inspectors found that the problem was first identified by licensee ;
engineers reviewing the system design bases in support of an RM flow l rate change. The engineers identified that both the TS and the UFSAR ,
required that the RMs remain operable following a seismic event for j P.eactor Coolant System (RCS) leakage detection purposes. Original system mechanical portions were appropriately designed to meet seismic requirements. However, the electrical power supplies were from non-safety related power and through cables which were not in seismically qualified cable trays. Engineering reviews for system
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design changes made in 1987 failed to note this discrepancy. l
- Additionally, in 1988 the mechanical piping was erroneously downgraded I to non-safety related quality. On June 11, 1996, the engineers ;
submitted DR N-96-ll32 documenting the problem. Operators promptly declared the RMs inoperable and complied with TS 3.4.6.1 action statement requirements for inoperable leakage detection systems.
After the RMs were declared inoperable, engineers prepared a DCP to route new electrical cables from the RMs through seismically qualified
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18 I cable trays and connect them to safety-related power supplies. During ,
the previous inspection period, the inspectors verified that the l TS action statement requirements were met during the period the RMs were '
inoperable and observed portions of the in-plant modifications (NRC Inspection Report Nos. 50-338,339/96-05). On June 28, 1996, the ,
installation of the new electrical supplies was successfully completed, i and the RMs were returned to operable status. Additionally, the piping j was returned to safety-related classification, several additional piping 1 supports were added, and a review of system changes was performed to ensure that no piping components had been incorrectly replaced or
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modified during the time the piping was classified as non-safety ;
quality. The inspectors verified that these actions were completed.
The inspectors also noted that the monitors were isolated by a containment isolation signal and were not required to function following l a design basis accident.
The inspectors found that the failure of the RMs to meet seismic qualifications meant that the RMs had not been able to meet design bases requirements. Since the design bases were not met, then the RMs did not meet TS requirements for operability. TS 3.4.6.1 requires that RCS leakage detection systems shall be operable including the containment j atmosphere particulate and gaseous RMs. Contrary to this requirement, i the containment atmosphere particulate and gaseous RMs were inoperable l on both units from original construction until June 11, 1996, and the l TS-required actions for inoperable RCS leakage detection systems were i not taken. This is identified as Non-cited Violation (NCV) 50-338, 339/96007-02 (EA 96-279): Inoperable Containment Radiation Monitors.
This licensee-identified and corrected violation is being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy.
c. Conclusions An NCV was identified for a failure to meet TS requirements for operability of RMs. The licensee displayed good initiative in identifying and correcting the problem.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls During the week of August 5, the following inspection activities were completed.
Rl.1 Transoortation of Radioactive Material (86750. Tl 2515/133) '
a. Insoection Scope The inspectors evaluated the licensee's transportation an,d radioactive materials programs for implementation of revised Department of Transportation and NRC transportation regulations for shipment of
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radioactive materials as required by 10 CFR 61.56 and 71.5, and 49 CFR 170 through 189.
b. Observations and Findinas l The inspectors reviewed the information concerning the May 17, 1996, l notification from the South Carolina Barnwell Low-Level Waste Facility that radioactive waste shipment No. 0596-5939 (96-0004), classified as Radioactive Material, low Specific Activity, Not Otherwise Specified, 7, described as solid oxides deposited on spent resin, and packaged in a poly High Integrity Container, was found to contain approximately 29.85 gallons (2.5 percent) of liquid. This is contrary to the requirements of South Carolina Radioactive Material License 097, Amendment 46, Condition 32 (C) which prohibits liquids in excess of one percent of total waste volume. The State of South Carolina assessed a civil penalty of one thousand dollars ($1000) in a May 22, 1996, letter to the licensee. The fine was paid by the licensee on June 12, 1996, which was prior to the June 18, 1996, due date. The inspectors reviewed the May 21, 1996, licensee response to the state explaining the corrective ,
actions taken to prevent recurrence. The June 7, 1996, licensee report in response to NRC Generic Letter 91-02, Report Mishaps Involving Low-Level Radioactive Waste Forms Prepared For Disposal, was also reviewed. The licensee was informed that this violation of the state material license and 10 CFR 61.56(a)(3) was currently under review for disposition by the Commission and will be tracked as URI 50-338, 339/96007-03 (EA 96-322): Failure to Meet State of South Carolina Radioactive Material License and 10 CFR 61.56(a)(3).
In addition, the inspectors also reviewed the receipt and Radioactive Materials Shipment Record for shipment 96-915 (RCP Motor) and found omissions, incorrect regulatory references, 'and errors. The shipment was returning the pump after refurbishment and was shipped by American Ecology Recycle Center, Oak Ridge, Tennessee, an agreement state licensee. The licensee notified the shipper of the errors, and a revised set of shipping papers correcting most of the errors was faxed to the licensee. The errant shipping papers were transmitted to the State of Tennessee for their information and followup.
c. Conclusions The licensee was informed that this violation of the state material license and 10 CFR 61.56(a)(3) was currently under review for disposition by the Commission and will be tracked as a URI. The transportation shipping papers by an agreement state licensee contained several apparent errors. This information has been forwarded to the State of Tennessee for follow-up.
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R2 Status of Radiation Protection Facilities and Equipment
R2.1 Radiation Monitor and Instrument Insoection (83750)
a. Inspection Scoce The inspectors reviewed selected radiation monitors to observe their i operational status and material c.ondition.
b. Observations and Findinas l l
The effluent monitors selected by the inspectors were found to be operational and their material condition acceptable. Selected radiation survey and frisking instruments were found operational and within calibration dates.
c. Conclusions No concerns with licensee facilities, equipment or analysis were identified during the inspection.
R2.2 Tours of Licensee Radioloaical Control Areas (RCAs) (83750)
a. Inspection Scope i During tours of the licensee facilities, the inspectors selectively i verified that radiological postings and labels were appropriate for the radiological hazard, b. Observations and Findinas The inspectors observed housekeeping and the control of contaminated and radioactive material within the Auxiliary Building, radioactive waste warehouse, scrap storage areas, and Fuel Handling Building were acceptable.
During a tour of the outside protected area in a location for large container storage, the inspectors observed a full storage trailer containing contaminated scaffolding without a completed radioactive material label as required by 10 CFR 20.1904(a). The licensee was informed, and a Health Physics (HP) Technician performed surveys and calculations were made to determine if the contents could be considered exempt from labeling under the exemption from label provisions of 10 CFR 20.1905. Surveys and calculations confirmed that the contents of the trailer were approximately 0.9 millicurie which significantly exceeded the 1 microcurie exempt quantity Appendix C value for Co-60.
c. Conclusions The licensee was informed that the absence of the required 10 CFR 20.1904(a) label information on a container of licensed material
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was a violation. This violation is identified as VIO 50-338, 339/96007-04: Failure to Label a Container as Required by 10 CFR 20.1904(a).
R7 Quality Assurance in RP&C Activities R7.1 Audits and Aporaisals (83750)
a. Insoection Scope The inspectors reviewed the licensee's program for identifying and
- correcting deficiencies or weaknesses related to the control of radiation or radioactive material, b. Observations and Findinas The inspectors selectively reviewed the DRs related to the control of radiation or radioactive material. During the review of the DR file, the inspectors observed that on February 29, 1996, at about 4
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an individual with contaminated clothing was released from the protected
area. The clothing contamination was above the licensee's procedural release limits. The details of the event were documented in DR N-96-477 dated March 21, 1996, and a memorandum from T. G. Chaffee to D. A.
Heacock transmitting Human Performance Evaluation System Report 96-01, i Recommendations for Loss of Control of Radioactive Material (Contaminated Clothing), dated March 28, 1996. The root cause was determined by the licensee to be human error and procedural deficiency.
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The contaminated clothing was retrieved at about 1:00 p.m., on February 29, 1996, and measurements of the clothing were completed at i approximately 4:00 p.m., the same day. The total activity measured on '
. the clothing was aporoximately 0.7 microcuries. The individual's evaluated skin dose as a result of the location of the material was calculated to be less than two mrem.
Licensee procedure HP-1061.020, Personnel Contamination Monitoring and Decontamination, revision 1, requires the approval of HP Supervision to authorize the release of an individual from an RCA with contamination greater than 100 cpm (net). Procedure HP-1061.020 further requires the approval of the Supervisor HP Operations (or designee) to authorize the release of an individual from the site with cor.tamination greater than 100 cpm (net). Licensee procedure VPAP-2101, Radiation Protection Program, revision 10, section 6.7, states that unauthorized and/or unknowingly releasing radioactive material increases the potential for l the uncontrolled spread of radioactive material. The required
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procedural authorizations were not obtained prior to the release of the individual wearing contaminated clothing from the RCA and subsequently )
from the site. The licensee was informed that this event was a )
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procedural violation. This violation is identified as VIO 50-338, 339/96007-05: Failure to follow Requirements of TS 6.8.1 and VPAP-2101.
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The inspectors observed the corrective actions that were implemented at the time of this inspection, except for implementation of the revised procedures. The inspectors attended an informational training meeting about this event for HP technicians.
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c. Conclusions ;
The licensee's program for identifying and correcting deficiencies or weaknesses related to the control of radiation or radioactive material was aggressive in identifying, assigning responsibilities and tracking to resolution corrective actions. One violation was identified.
S1 Conduct of Security and Safeguards Activities (71750) '
On several occasions during the inspection period, the inspectors performed walkdowns of the protected area perimeter to access security and general barrier conditions. No deficiencies were noted, and the inspectors concluded that security posts were properly manned and that ;
the perimeter barrier's material condition was properly maintained.
S8 Miscellaneous Security and Safeguards Issues S8.1 (Closed) URI 50-338. 339/94029-01: Changing of Calibration Records. I s
The licensee investigated an issue involving falsification of ,
calibration records of an intoxilyzer-alcohol analyzer. The ,
investigation substantiated the issue. The licensee entered the incident in the Security Event tog (10 CFR 73.71), terminated the individual involved, and made appropriate changes to procedure HSCP-0006, Breath Alcohol Analysis, revision 2, dated March 1,1994.
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 August 20, 1996. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the l inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED Licensee H. Royal, Superintendent, Nuclear Training C. Funderburk, Superintendent, Outage and Planning E. Grecheck, Assistant Station Manager, Operations and Maintenance J. Hayes, Superintendent, Operations D. Heacock, Assistant Station Manager, Nuclear Safety and Licensing M. Kansler, Vice President, Nuclear Engineering and Services P. Kemp, Supervisor, Licensing T. Maddy, Superintendent, Security W. Matthews, Station Manager M. McCarthy, Director, Nuclear Oversight D. Roberts, Supervisor, Station Nuclear Safety R. Saunders, Vice President, Nuclear Operations D. Schappell, Superintendent, Site Services R. Shears, Superintendent, Maintenance J. Smith, Superintendent, Station Engineering A. Stafford, Superintendent, Radiological Protection NRC B. Buckley, Project Manger, NRR j E. Imbro, Project Director, NRR INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensing Controls in Identifying, Resolving, and Preventing Problems IP 61726: Surveillance Observations IP 62700:- Maintenance Implementation
.IP 62703: Maintenance Observations i
IP 71707: Plant Operations IP 71750: Plant Support Activities I
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IP 83750: Occupational Radiation Exposure '
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IP 86750: Solid Radioactive Waste Management and Transportation of Radioactive Materials IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power i Reactor Facilities l
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, 24 IP 92903: Followup - Engineering TI 2515/118: Service Water System Operational Performance Inspection (SWSOPI)
TI 2515/133: Implementation of Revised 49 CFR Parts 100-179 and '[
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ITEMS OPENED AND CLOSED f Opened 50-339/96007-01 URI Review Compliance with 10 CFR 50.54k Requirements For Operator Presence at Unit Controls (Section 04.1) (EA 96-292)
EA 96-278 01014 VIO Inadequate Maintenance Procedure Causing CIV Inoperability (Section E8.1)
50-338, 339/96007-03 URI Failure to Meet State of South Carolina Radioactive Material License and 10 CFR 61.56(a)(3) (Section RI.1) (EA 96-322)
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50-338, 339/96007-04 VIO Failure to Label a Container as Required by 10 CFR 20.1904(a) (Section R2.2)
50-338, 339/96007-05 VIO Failure to Follow Requirements of TS 6.8.1 and VPAP-2101 (Section R7.1)
Closed 50-338/94019-02 URI Review TS 3.6.3.1 Applicability to Closed System l CIV (paragraph E8.1)
50-338, 339/94029-01 URI Changing of Calibration Records (paragraph S8)
50-338, 339/96004 LER Seismic Concerns Regarding the Containment Particulate and Gaseous Monitors !
(paragraph E8.2)
50-338, 339/96007-02 NCV Inoperable Containment Radiation Monitors ,
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(paragraph E8.2) (EA 96-279)
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