IR 05000269/1999006
| ML15261A413 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/17/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15261A412 | List: |
| References | |
| 50-269-99-03, 50-269-99-3, 50-270-99-03, 50-270-99-3, 50-287-99-03, 50-287-99-3, NUDOCS 9907060136 | |
| Download: ML15261A413 (16) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287, 72-04 License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503 Report Nos:
50-269/99-03, 50-270/99-03, 50-287/99-03 Licensee:
Duke Energy Corporatio Facility:
Oconee Nuclear Station, Units 1, 2, and 3 Location:
7800 Rochester Highway Seneca, SC 29672 Dates:
April 11 - May 22, 1999
.
Inspectors:
M. Scott, Senior Resident Inspector S. Freeman, Resident Inspector E. Christnot, Resident Inspector D. Billings, Resident Inspector Approved by:
C. Ogle, Chief, Projects Branch 1 Division. of Reactor Projects Enclosure 9907060136 990617 PDR ADOCK 05000269
EXECUTIVE SUMMARY Oconee Nuclear Station, Units 1, 2, and 3 NRC Inspection Report 50-269/99-03, 50-270/99-03, and 50-287/99-03 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspection. [Applicable template codes and the assessment for items inspected are provided below.]
Operations
Operations personnel responded promptly and reduced power on Unit 3 due to a decrease in condenser vacuum. Operators followed their procedure and stabilized the unit. (Section 01.3; [POS - 1 B])
During Unit 3 restart following an outage, operators exercised conservative decision making when they added boron before entering Mode 2 rather than rushing the startup of the unit. (Section 01.3; [POS - 1A])
A non-cited violation was identified for failure to assure an adequate change was made to an operations procedure. This inadequate change contributed to the inadvertent transfer of approximately 100 gallons of water from the Unit 1 letdown storage tank to the quench tank. (Section 01.4; [NCV - 3A, 3C])
The licensee's root cause investigation of a Unit 1 letdown storage tank level reduction problem was clear, logical, and well documenated. (Section 01.4; [POS - 5B])
A non-cited violation was identified for failure to initiate a corrective action report when the Unit 1 emergency hotwell makeup valve inadvertently opened. (Section 02.3; [NCV-5A])
The licensee exhibited operational weaknesses when a Unit 1 operations crew did not log spurious opening of the emergency hotwell makeup valve or submit a work request to investigate problems with the valves. (Section 02.3; [NEG - 3A, 3B])
The licensee exhibited a weakness in not identifying degradation in the material condition of the 2A feedwater pump. (Section 02.3; [NEG - 3A, 38])
The licensee exhibited good response to a plant design problem on the Unit 3 condenser circulating water booster pumps. (Section 02.3; [POS - SA])
Maintenance
The licensee properly followed the procedure; met the surveillance requirement; and, with a minor exception, generally adhered to software administrative controls during a Unit 2 nuclear instrument calibration. (Section M1.2; [POS - 2B, 3A])
The evaluation of problems identified in a problem investigation process report on the software used to calibrate nuclear instrumentation did not clearly address all the issues raised. (Section M1.2; [NEG - 5B])
Enqineerinq
A non-cited violation was identified for examples of failure to follow procedures for storage of QA-1 materials. (Section E3.1; [NCV - 4B, 4C])
An Unresolved Item was identified pending further NRC review of licensee controls for QA-1 oil. (Section E3.1: [URI - 2B, 41)
Plant Support Observed radiological controls were implemented as required by procedure and procedural requirements were adhered to by plant personnel. (Section R.1; [POS - 1C])
Report Details Summary of Plant Status Unit 1 began the period at 100 percent power and operated near that power level for the majority of the inspection period. The unit was shutdown on May 20, 1999, for a planned refueling outag Unit 2 began and ended the period at 100 percent.powe Unit 3 began the period at 100 percent power. Operators reduced power to 70 percent power on May 14, 1999, in response to a relief valve on one of the condensate steam air ejectors (CSAE) failing open resulting in decreased condenser vacuum. The unit went to Mode 3 later on May 14, 1999, to repair the lower motor bearing oil reservoir on reactor coolant pump (RCP)
3B2 and to repair a leak on Valve 3RC-2. Following repairs, the unit went critical on May 16, 1999, and returned to 100 percent power on May 17, 1999. The unit remained at 100 percent power for the rest of the inspection perio. Operations
Conduct of Operations 0 General Comments (71707)
Using Inspection Procedure (IP) 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo.2 Mispositioned Valves in Chilled Water System Inspection Scope (92901)
On April 8, 1999, the temperature in the Unit 3 control room began increasing. Licensee investigation identified that two valves on the chilled water makeup tank were not properly positioned. \\The inspectors reviewed the licensee's findings regarding this even Observations and Findings The mispositioned valves resulted in partial air binding of the chilled water system. This prevented cooling water from reaching the air handling units that cooled the Unit 3 control room. Without cooling, the temperature in the Unit 3 control room increased; however, the temperature did not exceed the Improved Technical Specification (ITS)
Surveillance Requirement (SR) 3.7.16.1 value of 80 degrees Fahrenheit (F). Control room temperature returned to normal, approximately 75 degrees F, after the licensee repositioned the valves and filled the chilled water syste Upon further review, the licensee determined that the mispositioned valves resulted in both trains of Unit 3's chilled water being inoperable. Therefore, due to both trains of chilled water being inoperable, ITS 3.7.16 Action E.1 required the immediate entry into ITS Limiting Condition for Operation (LCO) 3.0.3. The licensee has indicated that due to the requirement to enter LCO 3.0.3, as a result of both trains of Unit 3's chilled water being inoperable, Licensee Event Report (LER) 50-287/99-01 will be issued. The inspectors will review the LER after it is issue K 2 Conclusions Mispositioned valves resulted in increased Unit 3 control room temperature. Further NRC review of this issue will be conducted pending review of the associated LE.3 Unit 3 Power Reduction and Outaqe Inspection Scope (71707)
On May 14, 1999, operations personnel reduced power on Unit 3 due to a decrease in condenser vacuum. The inspectors responded to the control room to observe licensee actions and plant response. The unit was shut down later that day for an outage. The inspectors observed portions of the restart following the outag Observations and Findings When the inspectors entered the control room, the unit was stable at 73 percent powe The inspectors checked indications and trends for reactor coolant system (RCS)
pressure and temperature, pressurizer level, condenser vacuum, hotwell level, and upper surge tank level. Control room indications trended as expected for the events which occurred. The inspectors noted that operations personnel properly followed procedures with good command and contro The steam pressure controller for valve CSAE 3C had drifted high, which caused the relief valve to open. Operations personnel took manual control and reduced the pressure in an attempt to reseat the relief valve. The relief valve did not reseat and allowed air to enter the condenser as steam pressure was decreased. Operators reduced power, isolated the steam and vacuum side of the CSAE, and started the vacuum pumps. Vacuum stabilized at 22.5 inches which was 0.5 inches above the manual trip point. Normal vacuum is approximately 28 inches. The licensee initiated a problem report on the relief valve and the level of steam pressure reduction, and provided interim operational guidance on the steam pressure reduction at the CSA After the plant was stabilized following the steam pressure controller failure and the manual power reduction, the unit was taken to Mode 3 to perform scheduled repairs on the lower motor bearing oil reservoir on RCP 3B2 and to repair a leak on Valve 3RC-The inspectors observed the unit restart on May 16, 1999. During the startup, operations and reactor engineering personnel observed that the ITS required all safety rod groups to be fully withdrawn before exceeding shutdown margin limits,. i.e. enter Mode 2. Due to the short duration of the outage, xenon concentration in the RCS was decaying during this startup. The positive reactivity addition from the xenon decay allowed for only a small amount of time for pulling safety rods before shutdown limits were exceede Operations recognized this and added boron to account for the decay and provide enough time to pull safety rods in a deliberate fashio Conclusions Operations personnel responded promptly and reduced power on Unit 3 due to a decrease in condenser vacuum. Operators followed their procedure and stabilized the uni During Unit 3 restart following an outage, operators exercised conservative decision making when they added boron before entering Mode 2 rather than rushing the startup of the uni.4 Unit 1 Letdown Storage Tank (LDST) Level Drop Inspection Scope (71707)
On March 30, 1999, the licensee observed indications of a Unit 1 LDST level reductio The inspectors responded to the plant to assess the problem and actions taken by the license Observations and Findings Upon the inspectors' arrival at the site, the unit was found to be stable and the licensee was conducting a root cause investigation to determine what caused the LDST level reduction. Following a review of documentation, control room indications, and interviews of licensee personnel, the inspectors determined that the LDST had lost approximately 100 gallons to the unit's quench tank (QT). The inspectors also determined that the licensee was performing an RCS delithiation when the reduction in LDST level occurre The licensee had been performing RCS delithiation per Procedure OP/1/A/1103/004, Soluble Poison Concentration Control, Revision 46. While performing OP/1/A/1103/004, the licensee initiated Procedure OP/1/A/1104/017, Quench Tank Operation, Revision 48, to reduce level in the QT. Shortly after starting the QT pump, the operator at the controls observed a LDST level decrease and called the senior reactor operator (SRO) in charge of the unit. With a three-inch drop from 87 inches, the SRO decided to terminate both procedures. When this was accomplished, the LDST level decrease stopped. Shortly thereafter, the operators saw that QT level had increased by the same volume removed from LDST. The licensee initiated problem investigation process (PIP) report 1-099 1192. The inspectors verified that the QT pumping procedure was placed on administrative hold to preclude its use with the delithiating procedur The licensee's root cause team determined that the primary cause of the LDST level decrease was the inadequate development of a change to Procedure OP//A/1 103/00 The licensee had changed this procedure to account for a previous failure of air operated boundary valve 1 CS-26, during delithiation. The new boundary valve was downstream of piping leading to the QT. Performance of the QT Procedure OP/1/A/1104/017, while delithiating, opened a flow path to the QT from the LDST. The preparer and reviewer of the procedure revision had not detected the interaction of two procedures which allowed for the loss of LDST level and potential over pressurization of the piping. The licensee performed a subsequent analysis and determined that the lower pressure piping to the QT had not been damaged. The inspectors independently reviewed the licensee piping assessment and identified no concerns in the licensee's analysis. Aside from the above mentioned primary root cause, the licensee identified the following factors that contributed to the occurrence. First, three control room evolutions were performed at the same time thereby, reducing available supervisory oversight. Second, an incomplete pre-job brief was conducted prior to the two discussed pumping evolutions. These findings and associated corrective actions were also in the PIP. The inspectors verified that the training on the findings was disseminated to the operations staff. The inspectors concluded that the licensee's root cause analysis was clear, logical and well documente The change process to Procedure OP/1/A/1103/004 was inadequate in that it failed to detect an undesirable interaction with a procedure which could be performed at the same time, namely Procedure OP/1/A/1104/017. This constituted a violation of 10 CFR 50, Appendix B, Criterion VI, Document Control. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-03-01, Failure to Assure Adequate Procedure Chang This violation is in the licensee's corrective action program as PIP 1-099-119 Conclusions A non-cited violation was identified for failure to assure an adequate change was made to an operations procedure. This inadequate change contributed to the inadvertent transfer of approximately 100 gallons of water from the Unit 1 letdown storage tank to the quench tan The licensee's root cause investigation of a Unit 1 letdown storage tank level reduction problem was clear, logical, and well documente Operational Status.of Facilities and Equipment 0 Operations Clearances (71707)
The inspectors reviewed the following clearances during the inspection period:
99-0048 Isolate Keowee Unit 1 Tailrace and Forebay Relays
0-3-9-0873 3LP-5 EV-3A LPI Pump Suction
0-1-9-0918 1A HPI Pump
0-0-9-0162 Switchyard Red Bus The inspectors observed that the associated clearances were properly prepared and authorized, and that tagged components were in the required positions with the appropriate tags in place. The red bus was removed from service and planned work was not performed due to scheduling problems. The problem was entered into the licensee corrective action program as a PI The inspectors also reviewed the following clearances that were no longer in effect during the inspection period:
0-1-9-0856 Penetration Room Filter Train 1 B Drain Valve PMs
0-0-9-0162 Switchyard Red Bus The inspectors observed that the equipment was returned to service appropriately and that the tags were remove.2 Enqineered Safety Feature (ESF) System Walkdown (71707)
The inspectors walked down accessible portions of the following ESF system:
Unit 2 High Pressure Injection System Equipment operability, material condition, and housekeeping were acceptable in all cases. Several minor discrepancies were brought to the licensee's attention and were corrected. The inspectors identified no substantive concerns as a result of these walkdown.3 Material Condition Observations Inspection Scope (71707, 62707)
The inspectors conducted tours to observe the material condition of the facilit Observed problems were discussed with licensee managemen Observations and Findings 1)
On April 16, 1999, during a tour of the Unit 1 control room, the inspectors observed a decrease in upper surge tank (UST) level which the operators indicated was 0.5 feet. Control room operators had already dispatched a non licensed operator (NLO) to evaluate safety related air-operated Emergency Hot Well Fill Valve 1C-187. The NLO found no problems with the valve. Additionally, the operators set a temporary alarm on hotwell level that would have annunciated on a slightly higher than normal level. The inspectors checked the level.
transmitter (LT) and positioners for Valve 1C-187 and normal Hotwell Make Up Valve 1C-192. The inspectors found that hotwell level was varying about 2 to 2.5 inches, that the positioner for 1C-1 87 was stable and not moving, and that the positioner for 1C-192 had large swings in control air pressure. The inspectors checked the other two units and did not observe this swing. The inspectors reported this to the Operations Shift Manager (OSM) who was unaware of the UST level dro Due to licensee communications problems, the UST level drop was not pursued until several days later when the inspectors again began to ask additional questions. The system engineer reviewed the trend data and determined that 1C-1 87 had spuriously opened and dumped about 6000 gallons to the hotwell which decreased UST level from 11 feet to 9 feet. Six feet was the ITS minimum limit on UST level. On April 20, 1999, the system engineer initiated PIP 1-099 1503. For the intervening four day period, the inspectors verified that UST level had remained stabl Following PIP review by management, the licensee rapidly responded to address the problem. Operations closely monitored UST and hotwell levels. A root cause investigation was initiated. Investigation, partial disassembly, and testing of Valve 1C-1 87 revealed no problems with the valves's control system. The valve was returned to service and immediately failed opened, dropping UST level from 11 to 6.65 feet. Followup investigation revealed that a control signal had been present to close the valve. A safety-related solenoid valve associated with 1C 187 removed air from the positioner, closed the valve, and prevented UST level from exceeding the ITS limit. The inspectors closely reviewed the chart traces following the malfunction. The licensee replaced the positioner on 1C-1 87 and has had no further problems in the performance of 1C-187. The removed non safety positioner was sent to the vendor for failure evaluatio The inspectors further reviewed the events of April 16, 1999, and found several operations weaknesses. First, the OSM was not aware of the initial drop in UST level. Secondly, the operators did not log the spurious opening of Valve 1C-187 nor did they log an earlier-in-shift 400 gallon drop. Thirdly, no work request was initiated to have maintenance investigate potential problem NSD 208, Problem Investigation Process, Revision 20, contained significance criteria for events that required a PIP to be issued and for events requiring additional management attention. The inspectors considered the failure to initiate a PIP on April 16, 1999, when the initial problem occurred or in a timely period thereafter, to be a failure to comply with NSD 208 and a violation of 10 CFR 50 Appendix Criterion XVI, Corrective Action, in that conditions adverse to quality were not properly identified. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50-269/99-03-02, Failure to Identify a Valve's Condition Adverse to Quality. Repair of the valve positioner and counseling of the operations staff regarding the operators' communication problems, restored compliance. This violation is in the licensee's corrective action program as PIP 1-099-150 ).
On April 16, 1999, the inspectors observed that leaking seal steam from the 2A main feedwater pump (MFP) had nearly doubled. The steam was blowing on the auxiliary and emergency oil pump motors, the MFP trip circuitry, and on to motor control center 2XC which supplied critical non-safety related loads such as the iso-phase bus duct cooling fan. The inspectors pointed out the blowing steam problem to operations personnel. The licensee installed fans to divert the steam away from susceptible equipment. Subsequent inspection and testing revealed no damage to equipment. The on-shift NLOs had not detected the steam flow increase. After direction from management, the licensee initiated PIP 1-099 1916. The licensee used the occurrence as a training tool to counsel the NLOs as to the importance of reporting negative plant trend )
The inspectors were aware that differential pressure (DP) was increasing across the strainer at the suction of the Unit 3 condenser circulating water booster pumps. This pump supplied cooling water to the Unit 3 recirculating cooling water (RCW) heat exchanger. Operations had returned two pumps for Units 1 and 2 RCW to service and satisfactorily transferred all Unit 3 RCW loads to the Unit 1 and 2 system. The Unit 3 booster pumps were then valved out for, maintenance on the suction straine At the time of the cleaning of the strainer, the inspectors asked operations'
personnel to take pictures of the single strainer debris load. The pictures revealed that the strainer was internally coated with sticks, pine needles, debris, and leaves. The pictures were shown to plant management. Plant management discussed the problems associated with strainer cleaning with the operations staff. They determined that the single strainer arrangement caused undue burden on the operations staff during Unit 3 RCW system strainer cleaning. The licensee reopened existing PIP 3-097-2232 and initiated a request for booster pump strainer modificatio The above communication and plant observation problems were discussed with the licensee at multiple levels within the plant organization. The inspectors observed that the licensee used them to reinforce operator trainin Conclusions The inspectors identified a non-cited violation for failure to initiate a corrective action report when the Unit 1 emergency hotwell makeup valve inadvertently opene The licensee exhibited operational weaknesses when a Unit 1 operations crew did not log spurious opening of the emergency hotwell makeup valve or submit a work request to investigate problems with the valv The licensee exhibited a weakness in not identifying 2A feedwater pump material condition degradatio The licensee exhibited good response to a plant design problem on the Unit 3 condenser circulating water booster pump I. Maintenance M1 Conduct of Maintenance M General Comments Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance activities:
WO 98144970-04 Clean B SSW Strainer
PT/2/A/0230/015 HPI Motor Cooler Flow Test, Revision 13
WO 97103477 Implement Installation Procedure for NSM ON-22998
TN/5/5301/AL1/01 Relocate Transmitters and Relays in Keowee Control Room Panel, Revision 0, for Modification NSM ON-53014
IP/0/A/0075/04 Control Board Modification Procedure, Revision 7
IP/0/A/0310/12C Engineering Safeguards Logic Isolation and Cooling Channel 5, Revision 27
PT/2/A/0202/11 High Pressure Injection Pump Test, Revision 51
TN/2/A/2998/0/AL1 Replace Vital Instrument and Control Batteries 2A/B, Revision 2, for Modification NSM ON-22998
WO 98121028 Pre-Outage Assembly of Unit 1 Control Rod Drives
IP/0/A/0310/13C Engineered Safeguards Logic Isolation and Cooling Channel 6, Revision 31
.
WO 98004785 Implement Installation Procedure for NSM ON-53014
IP/0/A/0301/003T-2 Reactor Protective System Computer Calculation for Power Range Calibration Instrument Procedure, Revision
- WO 98134422-01 Diagnostic Test for 1 LPSW 251 and 252
WO 98154759-01 ACB-4, Repair Air Leak at Joint
PT/2/A/0203/006A Low Pressure Injection Pump Test - Recirculation (B Pump), Revision 54
PT/1 /A/0600/012 Turbine Driven Emergency Feedwater Pump Test, Revision 57
OP/1/A/1104/002A5 High Pressure Injection Pump Maintenance Test, Enclosure 4.1, Operation with 1A High Pressure Inoperable, -Revision
PT/1 /A/0204/007 Reactor Building Spray Pump Test (A Pump), Revision 63
WO 98152505-01 Unit 2 Control Rod Drive Check for Reactor Protection System Breaker Test
- PT/0/A/0501/022 Emergency Condenser Circulating Water Valve Stroke Test, Revision 56 Observations and Findings In general, the inspectors found the work performed under these activities to be professional and thorough. All work observed was performed with the work package present and in use. Technicians were experienced and knowledgeable of their assigned tasks. Quality control personnel were present when required by procedure. When applicable, radiation control measures were in plac Conclusions The inspectors concluded that the maintenance activities listed above were completed thoroughly and professionall M Power Range Nuclear Instrument (NI) Calibration Inspection Scope (61726, 37551)
On April 22, 1999, the licensee performed a regularly scheduled calibration of the Unit 2 power range NI instruments. The inspectors observed the calibration, reviewed the procedure, reviewed the results of the calibration, and reviewed the qualification of the software used to perform the calibration. The inspectors also reviewed the PIP database for those PIPs associated with reactor protection system (RPS).
b. Observations and Findinqs The licensee calibrated the NIs using Procedure IP/0/A/0301/003T-2, Reactor Protective System Computer Calculation for Power Range Calibration Instrument Procedure, Revision 22. During the calibration, technicians determined core thermal power from the operator aid computer (OAC), calculated new NI gain factors using an Excel spreadsheet, adjusted the Nis to the new gain factors, and compared the NI output as read on the OAC to the core thermal power. The technicians properly followed the procedure and used peer checks at each ste Procedure IP/O/A/0301/003T-2 stated that the Excel spreadsheet was Software and Data Quality Assurance (SDQA) Category E, which was non-safety-related as described in NSD 800, Software and Data Quality Assurance Program, Revision 5. The inspectors reviewed NSD 800 and found that software used for calibrations which directly affected Quality Assurance (QA) 1 functions was required to be SDQA Category B, i.e. safety related. NSD 800 gave RPS set points as an example where software must be SDQA-When questioned, the licensee stated that the spreadsheet did not calculate RPS set points and the procedure relied on the technician to confirm that the Nis met the acceptance criteria. The licensee further stated that Nis could be adjusted without even using the spreadsheet. The inspectors agreed with these statements because the calculations performed by the spreadsheet did not directly affect a QA-1 function. The gain factors calculated by the spreadsheet were not used to adjust any ITS RPS trip settings nor was it even required to calculate gain factors. ITS SR 3.3.1.2 required the NIs to be compared with a heat balance and be adjusted if they differed from the heat balance by two percent. This requirement was met by the visual compariso Because the data used to calculate core thermal power was the standard of comparison for the NI output, the inspectors questioned the SDQA category of the OAC and found it was SDQA Category C, non-safety related. The licensee responded that the core thermal power calculations were validated weekly by Procedure PT/O/A/0205/005, Thermal Power and Reactor Coolant Flow Calculations, Revision 15. This procedure determined core thermal power using an independent calculation that met SDQA
Category B requirements. The licensee stated this complied with NSD 800 which allowed a particular data set to be reclassified provided a separate, appropriate level SDQA document was developed for the data set and application. The inspectors reviewed Procedure PT/0/A/0205/005, the Nuclear Engineering Software Evolution Checklist for the POWCALC#.XLS spreadsheet used in Procedure PT/0/A/0205/005, and SDQA-10003-ONS, Software Control, Revision 1. These documents met the requirements of NSD 80 Because it was used by Procedure IP/0/A/0301/003T-2 as a comparison against core thermal power, the inspectors questioned whether or not a separate, appropriate level SDQA document existed for the NI output indication on the OAC. The licensee did not have one and initiated PIP 0-099-2023 to upgrade the NI output reading on the OAC to SDQA-B. The inspectors determined that the failure to have a separate SDQA document to verify the NI output indication to the OAC was not in compliance with NSD 800. The inspectors compared the NI output indication on the OAC against the NI indication on the control room front panel and found them to be in agreement. The failure to comply with NSD 800 constitutes a violation of minor significance and is not subject to formal enforcement actio During the review of PIPs on the RPS, the inspectors found that PIP 0-097-4066 previously raised the issues of OAC SDQA classification and use of separate non-safety related software to calculate RPS set points. The problem evaluation of this PIP explained that heat balance data was validated by SDQA Category B programs maintained by reactor engineering. However, it did not list the procedure number nor explain how the programs upgraded the OAC data. PIP 0-097-4066 also explained that separate software was not used to validate or verify the RPS calibration but did not address whether or not the software calculated RPS set points. Additionally, the PIP failed to mention the SDQA classification of the NI output to the OA Conclusions The licensee properly followed the procedure; met the surveillance requirement; and, with a minor exception, generally adhered to software administrative controls during a Unit 2 nuclear instrument calibratio The evaluation of problems identified in a problem investigation process report on the software used to calibrate nuclear instrumentation did not clearly address all the issues raise Ill. Engineering E3 Engineering Procedures and Documentation E Procurement Engineering Receipt and Storage of Safety-Related Parts Inspection Scope (37551)
The inspectors observed procurement engineering activities related to the purchase, receipt and storage of safety-related replacement parts. The areas of review included locations of parts, approved suppliers list verification, acceptable substitutes documentation, receipt inspection activities, self-assessments, and warehouse access controls and storag b. Observations and Findings The inspectors reviewed 15 procurement engineering packages for QA-1 replacement parts for which 10 CFR Part 21 requirements were applicable. Receipt inspection acceptance criteria were appropriately identified and special instructions clearly
described. The procurement data sheets demonstrated that for each of the replacement items procured, an adequate technical evaluation had been performe The inspectors reviewed 15 documentation packages for QA-1 and QA-2 (commercial grade dedication) parts. This review was to verify that replacement parts vendors were qualified to supply 10 CFR 50, Appendix B parts or had the appropriate certificate of compliance provided to document the quality of the parts. The qualified vendors list was supported by audits (discussed below) at a frequency of three years by the licensee or appropriate industry personnel. Vendor restrictions were identified in the packages and the restrictions were included in procurement documents and receipt inspection criteri The inspectors reviewed 16 equivalency evaluations for the acceptable substitutes of obsolete parts and eight parts classifications documents for safety-related and non safety-related equipment. The technical evaluations for those items reviewed adequately addressed differences between the original and the replacement par The inspectors reviewed 15 receipt inspection packages for both QA-1 and QA-2 part The inspectors observed the receipt inspection activities for the new Unit 1 control rod drive mechanisms (CRDMs). Appropriate acceptance criteria were specified and verifie The inspectors reviewed seven audits conducted by the licensee. The audits were conducted both by licensee and industry groups. Identified discrepancies were placed in the corrective action program and had been corrected. No outstanding issues were identifie The inspectors reviewed CF-412, Storage of Materials, Parts and Components, Revision 1, and toured portions of the warehouses on site to identify discrepancies between warehouse storage and access controls and the requirements of CF-412. The inspectors identified the following discrepancies: 1) QA-1 material being stored in a non documented location and examples of inadequate warehouse personnel access control; and, 2) CRDMs stored in the Maintenance Training Facility (MTF) which was not listed as an approved storage location per CF-412. Following identification of this issue, proper documentation was submitted to store the CRDMS at the Keowee Station and they were moved from the MTF. The inspectors also observed that access to Warehouse 2 was uncontrolled. CF-412 required access control to warehouse Following this, the licensee initiated PIP 0-099-1549 and counseled warehouse personnel. The inspectors considered these discrepancies to be examples of non compliance with CF-412. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy and is identified as NCV 50 269,270,287/99-03-03, Failure to Follow Procedures for Storage of QA-1 Materials. This violation is documented in the licensee's corrective action program as PIP 0-099-1408 and PIP 0-099-154 The inspectors also identified two separate items for followup. First, QA-1 oil and grease that had been issued were potentially not being stored properly after issue. QA-1 materials were required to be separated from non-QA items. The oil house in the turbine building basement had a single pipe to deliver both QA and non-QA oil from drums on the ground floor. This could result in contamination of the QA oil with non-QA oi Second, some materials designated for A level storage requirements were being issued and then stored in maintenance shop lockers which did not meet the A level storage requirements. This item will be identified as Unresolved Item (URI) 50-269/99-03-04, Storage Requirements for QA-1 Material-Following Issue pending further NRC revie Conclusions The inspectors identified a non-cited violation for examples of failure to follow procedures for storage of QA-1 material A URI was identified pending further NRC review of licensee controls for QA-1 oi E8 Miscellaneous Engineering Issues (92903)
E (Closed) LER 50-270/98-02: Emergency Start of Keowee Units Due to Unknown Causes This event was discussed in Inspection Report 50-269,270,287/98-05 (Section E2.1).
No new issues were revealed by the LER. This item is close IV. Plant Support Areas R1 Radiological Protection and Chemistry Controls R Radioloqical Protection (71750)
The inspectors periodically toured the Radiological Control Area (RCA) during the inspection period. Radiological control practices were observed and discussed with radiological control personnel, including RCA entry.and exit, survey postings, locked high radiation areas, and radiological area material conditions. The inspectors concluded that radiation controls were implemented as required by procedure and procedural requirements were adhered to by plant personne Si Conduct of Security and Safeguards Activities S General Comments (71750)
During the period, the inspectors toured the protected area and noted that the perimete fence was intact and not compromised by erosion or disrepair. Isolation-zones were maintained on both sides of the barrier and were free of objects which could shield or conceal an individual. The inspectors periodically observed personnel, packages, and vehicles entering the protected area and verified that necessary searches, visitor escorting, and special purpose detectors were used as applicable prior to entry. Lighting of the perimeter and of the protected area was acceptable and met illumination requirement V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 27, 1999. The licensee acknowledged the findings presented. No proprietary information was identified to the inspectors Partial List of Persons Contacted Licensee L. Azzarello, Design Basis Engineering Manager E. Burchfield, Regulatory Compliance Manager T. Coutu, Superintendent of Operations T. Curtis, Mechanical System/Equipment Engineering Manager G. Davenport, Operations Support Manager B. Dobson, Engineering Work Control Manager J. Forbes, Station Manager W. Foster, Safety Assurance Manager T. Hartis, Recovery Plan Coordinator D. Hubbard, Modifications Manager C. Little, Civil, Electrical & Nuclear Systems Engineering Manager
W. McCollum, Site Vice President, Oconee Nuclear Station B. Medlin, Superintendent of Maintenance M. Nazar, Manager of Engineering J. Smith, Regulatory Compliance J. Twiggs, Manager, Radiation Protection Other licensee employees contacted during the inspection included technicians, maintenance personnel, and administrative personne NRC D. LaBarge, Project Manager Inspection Procedures Used IP37551 Onsite Engineering IP61726 Surveillance Observations IP62707 Maintenance Observations IP71707 Plant Operations IP71750
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Plant Support Activities IP90712 In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP92901 Followup - Plant Operations Items Opened, Closed, and Discussed Opened 50-269/99-03-01 NCV Failure to Assure Adequate Procedure Change (Section 01.4)
50-269/99-03-02 NCV Failure to Identify a Valve's Condition Adverse to Quality (Section 02.3)
50-269,270,287/99-03-03 NCV Failure to Follow Procedures for Storage of QA-1 Materials (Section E3.1)
50-269/99-03-04 URI Storage Requirements for QA-1 Material Following Issue (Section E3.1)
Closed 50-270/98-02 LER Emergency Start of Keowee Units Due to Unknown Causes (Section E8.1)
Discussed 50-287/99-01 LER Control Room Cooling Inoperable Due to Valve Misalignment (Section 01.2)
List of Acronyms CFR Code of Federal Regulations CRDM Control Rod Drive Mechanism CSAE Condensate Steam Air Ejectors DP Differential Pressure ESF Engineered Safety Feature F
Fahrenheit IP Inspection Procedure
ITS Improved Technical Specifications LCO Limiting Condition for Operation LDST Letdown Storage Tank LER Licensee Event Report
.LT Level Transmitter MFP Main Feedwater Pump MTF Maintenance Training Facility NCV Non-Cited Violation NI Nuclear Instrument NLO Non-Licensed Operator NRC Nuclear Regulatory Commission NSD Nuclear Site Directive OAC Operator Aid Computer OSM Operations Shift Manager PIP Problem Investigation Process QA Quality Assurance QT Quench Tank RCA Radiological Control Area RCP Reactor Coolant Pump RCS Reactor Coolant System RCW Recirculating Cooling Water RPS Reactor Protection System SDQA
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Software and Data Quality Assurance SR Surveillance Requiremen SRO Senior Reactor Operator URI Unresolved Item UST Upper Storage Tank WO Work Order