IR 05000269/1999002
| ML15261A405 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/05/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15261A404 | List: |
| References | |
| 50-269-99-02, 50-269-99-2, 50-270-99-02, 50-270-99-2, 50-287-99-02, 50-287-99-2, NUDOCS 9905190094 | |
| Download: ML15261A405 (25) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
- REGION 11 Docket Nos:
50-269, 50-270, 50-287, 72-04 License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503 Report Nos:
50-269/99-02, 50-270/99-02, 50-287/99-02 Licensee:
Duke Energy Corporation Facility:
Oconee Nuclear Station, Units 1, 2, and 3 Location:
7812B Rochester Highway Seneca, SC 29672 Dates:
February 28 - April 10, 1999 Inspectors.:
M. Scott, Senior Resident Inspector S. Freeman, Resident Inspector E. Christnot, Resident Inspector D. Billings, Resident Inspector R. Schin, Reactor Inspector (Section E8.1)
E. Testa, Reactor Inspector (Sections R1.2, R2.2, R2.3, R7)
E. Girard, Reactor Inspector (Sections E7, E8.2)
M. Thomas, Reactor Inspector (Sections E2.2, E8.3)
Approved by:
C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects 9905190094 990505 PDR ADOCK 05000269 G
PDR Enclosure
EXECUTIVE SUMMARY Oconee Nuclear Station, Units 1, 2, and 3 NRC inspection Report 50-269/99-02, 50-270/99-02, and 50-287/99-02 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspection, as well as the results of announced regional based inspections. [Applicable template codes and the assessment for items inspected are provided below.]
Operations
Following a Unit 2 transient and reactor trip, the operators properly followed the emergency operating procedures, were aware of plant conditions, demonstrated good command and control, used good communications, and had good shift management oversight. (Section 01.2; [POS - 1B, 3A, 3C])
The licensee was unaware of the extent to which differential pressure problems existed on the siphon seal water strainers, both in how long the problems remained after high pressure service water testing and whether or not similar problems exist after changes in low pressure service water system flow rate and pump operation. (Section 02.4; [WEAK
- 2B, 4B])
The licensee had performed monthly testing of the high pressure service water pumps based on an informal interpretation of a selected licensee commitment from August 1995 until recently changed. (Section 03.1; [WEAK - 2B, 4C])
The inspectors identified a non-cited violation for failure to follow overtime control procedures when requesting and granting overtime. This failure resulted from a lack of management oversight and control of the overtime process. (Section 08.2; [NCV - 1A, 3C])
A non-cited violation was identified involving two cases where operators failed to follow procedure during a May 1998 high pressure injection pump surveillance test, resulting in a temporary loss of reactor coolant seal flow. (Section 08.3; [NCV - 1A, 3A, 3B])
The inspectors identified a non-cited violation for failure to properly check the suitability and adequacy of the design for the replacement of valve 2HP-1 16. (Section 08.3; [NCV
- 2A, 4A, 4B])
The inspectors identified a non-cited violation for two examples of failure to promptly correct known deficiencies on valve 2HP-1 16 and change critical procedures that operate it. (Section 08.3; [NCV - 5B, 5C])
Enqineering
Partial discharge testing of the underground cables from the Keowee station was easily understood, covered sufficient parameters to make well informed decisions, and proved to be an effective method of measuring and locating cable degradation. (Section E2.1;
[POS - 2B, 4C])
The licensee 's implementation of the post-modification/post-maintenance testing initiative was consistent with the scope and goals specified for this recovery plan ite An action plan and schedule had been developed for implementation of the remaining corrective actions (Recovery Plan Item TD6 - closed). (Section E2.2; [POS - 2B, 5B, 5C])
- The licensee's implementation of the Problem Investigation Process root cause quality improvement initiative was not consistent with the scope and goals specified in the initiative. The goal for this initiative had not been achieved and important actions specified by the licensee for improvement of root cause quality had not been adequately implemented (Recovery Plan Item SA2). (Section E7.1; [NEG - 5B, 5C])
License Event Report 50-269/99-01 was not completely accurate in describing the emergency feedwater system licensing basis and design, nor did it address the safety significance of increased reliance on manual actions in place of automatic actions. The licensee had dissenting comments on this issue (Section E8.1, X1; [NEG - 4A, 5B])
Plant Support
Except for minor problems in the reactor coolant pump refurbishment building, the radioactive material storage areas, health physics facilities, turbine building, and waste storage building were found to be properly posted and material appropriately labele (Section R1.2; [POS - 1C))
Access to locked high radiation areas was being controlled. (Section R1.2; [POS - 1C])
Radiation worker doses were being maintained well below regulatory limits and the licensee was maintaining exposures as low as reasonably achievable. (Section R1.2;
[POS - 1C])
Radiation work activities associated with the independent spent fuel storage installation were appropriately planned and doses to workers controlled effectively. (Section R1.2;
[POS - 1 C])
The failure to properly control storage of radioactive in the change room personnel lockers was identified by the inspectors as a non-cited violation. (Section R2.1; [NCV 1C, 2A, 3C])
Radiation and process effluent monitors and environmental monitors were being maintained in an operational condition in compliance with Technical Specification requirements and the Updated Final Safety Analysis Report commitments. (Section R2.2; [POS - 1C, 2A])
The inspectors concluded that electronic dosimeters were being calibrated as required and that internal assessment of individual intakes of radioactive material met regulatory requirements. (Section R2..3; [POS - 1C])
The inspectors determined the licensee was conducting formal radiological protection and chemistry audits as required by Technical Specifications and conducting self assessments. The licensee was developing corrective action plans, trending, and completing corrective actions in a timely manner. (Section R7; [POS - 5A, SB, 5C])
Report Details Summary of Plant Status Unit 1 began and ended the period at 100 percent powe Unit 2 began the period at 100 percent power. The unit tripped from 98 percent power on February 28, 1999, following a transient in the electro-hydraulic control (EHC) syste Following repairs, the unit went critical on March 2, 1999, and returned to 100 percent power on March 3, 1999. The unit remained at 100 percent power for the rest of the inspection perio Unit 3 began and ended the period at 100 percent powe. 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 Unit 2 Transient and Reactor Trip Inspection Scope (93702)
On February 28, 1999, at 3:41 p.m., Unit 2 experienced a slight power increase above 100 percent power when the normal power supply for the EHC system failed and the system automatically shifted to the backup power supply. At 8:30 p.m., while the licensee was troubleshooting the problem, Unit 2 tripped from 98 percent power. At the time of the trip, the inspectors were onsite observing and reviewing the activities associated with the transient earlier that afternoon. The inspectors performed post transient and post-reactor trip followup reviews, as well as observed activities associated with reviews of the transient and reactor trip by the license b. Observations and Findinqs When the inspectors responded to the site for observation of the transient conditions, Unit 2 was stable with its feedwater control and the rod control systems in manual. By placing these systems in manual, the operators were able to effectively control the transient and stabilize the unit at 98 percent power. As a result of the transient, reactor power initially peaked at 100.4 percent power for a brief time and steam pressure peaked at 928 pounds per square inch gauge (psig; normal is 900 psig).
The licensee determined that a failed current limiting fuse, referred to as an amp-trap, caused the loss of the normal power source. Following the loss of normal power, the EHC system shifted to its backup power source in order to prevent a turbine trip. The backup power source was, by design, set to a lower voltage than the normal sourc This shift in voltage caused a slight closure of the turbine control valves, resulting in the plant transient. Several hours after the initial transient, the amp-trap momentarily closed and then reopened, which re-established the normal power to the EHC system long enough for the system to transfer to the normal supply and then immediately transfer back to the backup supply. This power transfer upset the EHC system enough to cause the turbine valves to fully close and resulted in a reactor trip on high reactor coolant system (RCS) pressure. X-rays of the removed amp-trap indicated an open circuit, but with the internal bus bar still intact. Further analysis showed a crack in the fuse material soldered to the end cap. The licensee documented the findings and corrective actions in Problem Investigation Process reports (PIP) 2-099-0770 and 0771. Licensee Event
Report (LER) 50-270/99-01, Equipment Failure Results in a Reactor Trip, was issued on March 30, 199 Following the reactor trip, the plant was stable, in hot shutdown condition, with the control rods fully inserted. The inspectors checked indications and parameters. They confirmed that the trip of the reactor was due to high RCS pressure. All indications showed the expected post-trip results. The inspectors observed that the operators properly followed the emergency operating procedures, were aware of plant conditions, demonstrated good command and control, used good communications, and had good shift management oversigh Conclusions Following a Unit 2 transient and reactor trip, the operators properly followed the emergency operating procedures, were aware of plant conditions, demonstrated good command and control, used good communications, and had good shift management oversigh Operational Status of Facilities and Equipment 0 Operations Clearances (71707)
The inspectors reviewed the following clearances during the inspection period:
99-0368 Keowee Underground Power Cable Test
0-2-9-0353 Replace Control Battery 2CB
99-381 Unit 2 Keowee ACBs - Load Reject Test The inspectors observed that the clearances were properly prepared and authorized, and the tagged components were in the required positions with the appropriate tags in plac.2 Containment Isolation Lineup (71707)
The inspectors reviewed the following portion of the containment isolation lineup during the inspection period:
Unit 1 East and West Penetration Rooms
Unit 3 West Penetration Room The inspectors observed that those portions of the lineup reviewed were in accordance with plant operating procedures and the Updated Final Safety Analysis Report (UFSAR).
0 Enqineered Safety Feature (ESF) System Walkdown (71707)
The inspectors walked down accessible portions of the following ESF systems:
Unit 1 High Pressure Injection
Unit 1 and 2 High Pressure Service Water
Unit 3 High Pressure Injection
Keowee Units 1 and 2 Alternating Current (AC) Electrical Systems
125 Volt Vital Direct Current (DC) Instrumentation and Control Power 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.4 Differential Pressure (DP) on Siphon Seal Water (SSW) Strainers Inspection Scope (37551, 71707)
The inspectors reviewed the occurrences of high SSW strainer DP following testing of the high pressure service water (HPSW) syste b. Observations and Findings In October 1998, the DP across the A train SSW strainers increased noticeably following HPSW pump testing. The licensee concluded that non-safety-related HPSW pump testing was disturbing debris in the pipes and that some of the debris was collecting in the safety-related SSW strainers. The licensee documented this in PIP 2-098-4990 and implemented a corrective action to check SSW strainer DP about 30 minutes after HPSW pump testing and clean the strainer if DP exceeded 4 pounds per square inch differential (psid). The licensee also determined that the strainer was operable if the DP were 25 psid or les On March 5, 1999, the inspectors observed the strainers about 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after HPSW testing. The DP was about 9.5 psid and was rising slightly. The inspectors informed the licensee of the high DP and the licensee cleaned the strainers and documented the occurrence in PIP 2-098-4990. On March 20, 1999, two days after a HPSW pump test, the inspectors again found 10.5 psid on the strainer gage. When questioned about this and any method of tracking the occurrences or fixing the problems, the licensee determined they would log all occurrences of high SSW strainer DP. The inspectors determined that the licensee was unaware of the extent of the SSW strainer problem, especially in how long after HPSW testing the strainer debris entrainment continue The inspectors also determined that although high strainer DP occurred at times longer than initially believed by the licensee, it has not disabled any SSW train. To date, operator rounds have been of sufficient frequency to detect a proble The inspectors questioned whether or not a similar situation existed with the low pressure service water (LPSW) system. That is, would changes in LPSW flow rate and pump operation cause the same high DP occurrence on SSW Strainers. The licensee has proposed to answer this question by testing the B SSW train under conditions of stopping and starting LPSW pumps to determine if strainer DP will increase. This testing has yet to be schedule Conclusions The licensee was unaware of the extent to which differential pressure problems existed on the siphon seal water strainers, both in how long the problems remained after high pressure service water testing and whether or not similar problems exist after changes in the low pressure service water system flow rate and pump operatio Operations Procedures and Documentation 0 Elevated Water Storage Tank (EWST) Operability During HPSWTestinQ Inspection Scope (71707)
During routine testing of the HPSW pumps, the licensee had been following a practice of
testing the pump start logic by switching off the HPSW jockey pump and allowing the EWST to slowly drain until the HPSW pumps started. The inspectors reviewed the applicability of this practice to Selected Licensee Commitments (SLC) for HPSW to support LPS Observations and Findings On March 17, 1999, as part of Procedure PT/O/A/0250/005, High Pressure Service Water Functional Test, Revision 14, the licensee reduced the level in the EWST from the normal level of 90,000 gallons to 60,000 gallons in order to test the start logic of the standby HPSW pump. To accomplish this, the base HPSW pump (which starts at 70,000 gallons) and the jockey pump were turned off. SLC 16.9.8, HPSW Pump Requirement to Support LPSW, dated November 23, 1998, stated that the EWST was considered out of service if the level could not be maintained greater than 70,000 gallons. The basis for the SLC stated that 70,000 gallons was chosen because it was the lowest level that would exist during normal daily operatio The inspectors questioned the operability of the EWST during monthly testing when the level was lowered to 60,000 gallons to test the standby pump. The licensee stated that the EWST was not out of service during testing because they could maintain level by starting a HPSW pump. Furthermore, the licensee stated that the EWST was operable at levels less than 60,000 gallons because the tank was only required to maintain a flow rate of about 500 gallons per minute for 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee initiated PIP 0-099 1054, completed a formal calculation which confirmed EWST operability to 55,000 gallons, and began changes to the SL The inspectors reviewed the UFSAR, the HPSW Design Basis Document (DBD), and past revisions to both SLC 16.9.8 and Procedure PT/0/A/0250/005. The SLC was changed in August 1995 to provide clarification as to when the HPSW system was considered available to support LPSW and included the 70,000 gallons requirement. All previous revisions of the procedure contained steps to test the standby HPSW pump by draining the EWST to 60,000 gallons. The inspectors also found that the question of EWST operability during monthly HPSW testing had been posed before and each time was answered with arguments similar to that above. However, no formal answer or review was documented by the licensee. Based on these reviews, the inspectors agreed that the licensee's interpretation of SLC 16.9.8 was reasonable; however, the licensee had continued HPSW pump testing under an informal SLC interpretation from August 1995 until the recent changes to the SL Conclusions The licensee had performed monthly testing of the high pressure service water pumps based on an informal interpretation of a selected licensee commitment from August 1995 until recently change Miscellaneous Operations Issues (92901, 92700)
0 (Closed) LER 50-287/97-04-00: Deficient Procedure Results in a Missed Technical Surveillance Check This issue was previously identified as Non-Cited Violation (NCV) 50-287/97-16-02:
Inadequate Procedure Causes Failure to Complete Required Technical Specification Surveillance. Accordingly, the subject LER is close.
0 (Closed) Unresolved Item (URI) 50-269,270,287/98-11-03: Overtime Procedures and Controls This URI was opened to determine if use of overtime had resulted in any operational events or transients. The inspectors reviewed past events, PIP 4-099-0116 (which documents the adverse trend), and personnel overtime records. The inspectors did not identify any adverse impacts on safety-related equipment or plant operation as a resul Technical Specification (TS) 6.4, Station Operating Procedures, Section 6.4.4, states in part, "Administrative procedures shall be developed and implemented to limit the working hours of station staff who perform safety-related functions." Nuclear System Directive (NSD) 200, Control of Overtime, Revision 5, required proper completion of overtime requests. Contrary to the above, multiple instances were documented of failure to complete the requirements of the NSD. Based on the inspectors' review of NSD 200, the documented failures were of low significance without adverse impact. The licensee has verified compliance with the requirements and has increased management oversight of this area. 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 02-01, Failure to Follow Overtime Procedure. This violation is in the licensee's corrective action program as PIP 4-099-0116. This URI is close.3 (Closed) URI 50-269,270,287/98-06-04: Unit 2 Valve Misposition Issues In May 1998, Unit 2 High Pressure Injection (HPI) cross-connect valve 2HP-116 was not properly opened for surveillance test PT/2/A/0202/01 1, HPI Pump Performance Test, resulting in a momentary loss of reactor coolant pump (RCP) seal supply pressure. The URI stemmed from apparent inappropriate actions by the operations staff and problems with the valve positioning and position indicatio The licensee determined that one member of the operations test group manually operated the valve's remote operator from the hatch area above the HPI pump room until that test technician felt the valve was fully open. Following discussion among test personnel, they manually operated the remote operator to shut the valve. Then they operated the remote operator the same number of turns and agreed the valve was ope In fact, the valve was not fully open and this subsequently resulted in markedly reduced seal flow to the RCPs. No test personnel went into the HPI pump room to observe the local valve position indicator. The licensee concluded that Procedure OMP 1-2, Rules of Practice, Revision 25, required diverse means, such as observing a manual position indicator, be employed to ensure that the valve was in the proper position. This is one example of failure to follow procedure. The licensee changed PT/2/A/0202/011 to specifically require test personnel to verify local indication of the valve. The inspectors verified the procedure changes and observed operation of the same valve in Units 1 and 3 (1, 3HP-116).
During the event, the 2A HPI pump started automatically on low RCP seal flow. The operator at the controls shut the pump off without discussing the action with the senior reactor operator. The licensee determined that the operator made an inappropriate action and wrong assumption about the functioning of RCP seal injection and therefore, did not comply with the requirements of OMP 2-1, Duties and Responsibilities of on Shift Operations Personnel, Revision 49. This is a second example of failure to follow procedure. The inspectors verified that reactor operators had been provided and had read the details of this event as a corrective action. These examples are a violation of 10 CFR 50, Appendix B, Criterion V. 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 50-270/99-02-02, Failure to Follow Procedure for Valve and Pump Operation - Two Examples. This violation is in the licensee's corrective action program as PIP 0-098 587 The inspectors agreed that with local position checks, valves 1,2,3HP-116 would be operable and in their required position. These valves are normally closed and remain closed except for surveillance testing. The inspectors have also regularly verified the position of the valve The inspectors reviewed previous PIPs written on valves 1,2,3HP-116 and the modifications that installed the valves. Various problems, including remote operator cable length, cable restraint, and the cable to handwheel shear pins were identified as primary problems after the first valve was installed on Unit 3. These problems were not addressed in the modifications for the valves on Units 1 and 2. Generally, testing specified in the modifications was a post-installation valve stroke without accounting for actual system conditions. Additionally, the surveillance test in use during the failure of valve 2HP-1 16 was performed as a post-modification test on Unit 1, but was not performed as such following the modification in Units 2 and 3. 10 CFR 50, Appendix B, Criterion Ill, requires measures to ensure that components are suitable for the safety related application. The criterion also requires design control measures for verifying or checking the adequacy of design. The inspectors considered the failure to address the problems discovered after installation of the first valve and failure to account for system conditions during testing as a failure to properly check the suitability and the adequacy of the design. This constitutes a violation of 10 CFR 50, Appendix B, Criterion Ill. 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 50-269,270,287/99-02-03, Failure to Provide Adequate Valve Replacement Design Control. This violation is documented in the licensee's corrective action program as PIP 0-098-587 On February 19, 1999, during surveillance testing on the 2C HPI pump, valve 2HP-1 16 failed in the open position. The inspectors interviewed the operator involved and found that the valve was hard to operate, but that the operator was aware that 39 turns were required to open the valve. In the process of opening the valve the shear pin at the handwheel broke. This event was documented in PIP 2-099-0652 with a reference to PIP 0-098-5872 for corrective action. The corrective actions in PIP 0-098-5872 had not yet been implemented. The inspectors considered this second failure of valve 2HP-116, in conjunction with a lack of formal action on the corrective actions of PIP 0-098-5872, as one example of failure to take prompt corrective actio The inspectors reviewed Procedures AP/1,2,3/A/1700/014, Loss of Normal HPI Makeup or Letdown, and OP/1,2,3/A/1104/002, HPI System, and found that both contained instructions for operating valves 1, 2, 3 HP-116. Neither of these procedures had been changed to require local verification of position comparable to the changes done to surveillance procedure PT/2/A/0202/01 1. The inspectors considered this the second example of improper corrective action and constituted a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. 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 50-270/99-02-04, Failure to Take Prompt Corrective Actions - Two Examples. This violation is documented in the licensee's corrective action program as PIP 0-098-5872. This URI is close II. Maintenance M1 Conduct of Maintenance M General Comments Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance activities:
PT/2/A/0261/010 Essential Siphon Vacuum Test, Revision 5
- WO 98112441-02 Inspect Fuses in 4160 Volt Switchgear
IP/0/A/0310/012B Safeguards System Logic Subsystem 1, LPI Channel 3, On-line Test, Revision 29
PT/1/A/0400/00 SSF-RC Makeup Pump Test, Revision 27
IP/O/A/2000/01 U Keowee Underground Power Cable Partial Discharge Test, Revision 0
WO 98098039 Support Partial Discharge Test of Keowee Underground Power Cable
TN/2/A/2998/0/AL1 Replace Vital Instrumentation and Control Batteries 2A/B Revision 2
IP/0/A/0310/14B Engineered Safeguards System Analog Channel B Line Calibration, Revision 33
WO 97103477 Support Replacement of Batteries 2A/B
WO98134422-01 Diagnostic Test of 1 LPSW-251
WR98071298 Unit 3 Hydrogen Purity - Hygrometer b. 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 Ill. Engineering El Conduct of Engineering E Keowee Emergency Power Proiect (37551)
On January 19, 1999, the licensee received the final report on the reliability of the Oconee emergency power system entitled, Final Report - Oconee Nuclear Station, Unit 1, 2, and 3 - Emergency Electrical Power System. The licensee entered the report recommendations into the corrective action program via PIP 0-099-040 E2 Engineering Support of Facilities and Equipment E Keowee Load Tests and Underground Power Cable Test Results Review Inspection Scope (37551)
The licensee performed a partial discharge test to determine the condition of the underground power cables from Keowee to transformer CT-4. The inspectors witnessed the performance of the test and reviewed the result b. Observations and Findings The partial discharge test slowly increases voltage on each cable to 16 kilovolts (KV) or until a partial discharge occurs. From this the licensee can determine the magnitude and distance to any degraded spots on the cable. This was the second in a series of pro active predictive tests. The inspectors considered the test to be non-destructive, having reasonable criteria with clear action levels and required actions. The preliminary results indicated that four of the six cables (two cables per phase) were slightly degrade Three cables had partial discharges in the 8 to 12 KV range and one was in the 12 to 16 KV range. Per the test criteria, the cables were considered degraded, but still able to perform their safety function. However, they must be retested in six months. The licensee entered the finding into PIP K-099-0947 to track the testing and the required actions. The licensee has already scheduled the next test and has made contact with a cable vendor for potential cable procuremen The inspectors reviewed the procedure, attended the pre-job briefing, and watched the test performance. The inspectors determined that the test data was easily understood, covered sufficient parameters to make well informed decisions, and met the stated goals of the tests. The inspectors agreed with the results of the test. The inspectors also observed that the partial discharge test could be used as a predictor of further underground cable degradation. The pre-job briefing was very comprehensive, explained the purpose of the test, and the basic technology used for the test. Test personnel properly followed the procedur Conclusions Partial discharge testing of the underground cables from the Keowee station was easily understood, covered sufficient parameters to make well informed decisions, and proved to be an effective method of measuring and locating cable degradatio E Post-Modification/Post-Maintenance Testing (PMT) Process (Recovery Plan Item TD6) Inspection Scope (37550, 40500)
The inspectors reviewed the implementation of this item to determine if the scope, schedule, and goals were consistent with the description in the Oconee Recovery Pla b. Observations and Findings This recovery plan item described that the PMT process would be improved by the implementation of short-term and long-term corrective actions developed by a PMT improvement team that was established in April, 1997. The improvement team report and recommendations were documented in PIP 0-097-1691, dated, June 3, 199 This recovery plan item was reviewed previously and discussed in NRC Inspection Report (IR) 50-269,270,287/98-09. In that IR, the NRC concluded that the licensee's implementation of the PMT improvement initiative did not appear to be well focused. The trends and areas of deficient performance were not clearly defined and corrective actions did not clearly address the stated root causes. It was not evident that the PMT program improvements would assure that all PMTs were correctly designated, scheduled, and executed, which was the stated goal for this recovery plan item. A continuous improvement team (CIT), which was planned by the original team, was established in October 1998, to evaluate the effectiveness of the recommendations implemented. The charter for this CIT included the identification of indicators to assess PMT performanc During this current inspection, the inspectors noted that the licensee had addressed the weaknesses in this recovery plan item that were discussed in IR 50-269,270,287/98-0 The inspectors noted that the CIT had performed an assessment of each of the
corrective actions identified in PIP 0-097-1691. The CIT reviewed each short-term corrective action and determined if the action had been completed. The CIT provided justifications for those short-term actions which had not been completed and were determined not to be necessary. The CIT also ensured tha't the long-term corrective actions which had not been completed by their scheduled dates did get completed. The inspectors noted that the CIT initiated additional corrective actions in PIP 0-097-1691 to further enhance the PMT process in areas that were not previously addressed in this PIP. The licensee developed a PMT CIT implementation plan for the remaining corrective actions in PIP 0-097-1691. All of the remaining corrective actions were scheduled to be completed by December 31, 199 Conclusion The inspectors concluded that the licensee 's implementation of the post modification/post-maintenance testing initiative was consistent with the scope and goals specified for this recovery plan item. An action plan and schedule had been developed for implementation of the remaining corrective actions. The licensee had addressed the weaknesses in this recovery plan item that were discussed in IR 50-269,270,287/98-0 The inspectors' review of this item is complet E7 Quality Assurance in Engineering Activities E PIP Quality Improvements - Root Cause Quality (Recovery Plan Item SA2) Inspection Scope (37550, 40500)
The inspectors assessed the licensee's implementation of initiative N9834, Root Cause Quality. A previous NRC inspection of the licensee's implementation of this initiative was performed in December 1998 and documented in NRC IR 50-269,270,287/98-11. That inspection concluded that implementation was not adequate. The current inspection focused primarily on the licensee's correction of the deficiencies that led to that conclusion. In addition, the inspectors reviewed a recent example of an equipment failure root cause analysis performed by the licensee to gain perspective on the quality of the licensee's analyse b. Observations and Findinqs Initiative N9834 was defined and discussed in the Oconee Recovery Plan (December 1998 update) under the Management Focus Area of Self Assessment. In defining the purpose and scope of the initiative, the Recovery Plan stated that "initiatives are in place to raise the level of Human Performance and Equipment Root Cause Quality to be measured using a 16 point checklist." The goal of the initiative was to achieve a quarterly average score of 90% (14.4 points) quality using the 16 point checklist. In an assessment of effectiveness (dated January 11, 1999), the Recovery Plan reported that the 1998 quarterly average scores were 88%, 82%, 88%, and 84%; and that efforts were in progress with an "action plan" to improve root cause qualit The findings of this current inspection were similar to those of the December 1998 inspection reported in IR 50-269,270,287/98-11:
The licensee's target completion date for this initiative was December 31, 199 The licensee had not achieved the 90% quarterly goal. No trend was apparen The average score for the most recent quarter (last quarter 1998) was 84%. At the time of the inspection reported in IR 98-11, the average for the most recent quarter was 88% (third quarter 1998).
The licensee's action plan for this initiative specified that human performance root cause analyses with scores of less than 13 (81%) would be returned for revision, and that feedback would be provided to root cause investigators. IR 50 269,270,287/98-11 reported that analyses scoring less than 13 were not being returned for revision and that no feedback was being provided to the root cause investigators. In the current inspection, the inspectors found that analyses were still not being returned for revision when the scores were less than 13. The graders reported that analyses that would score less than about 8 (50%) were returned for revision without grading. The graders were now providing the scored checklists to the investigators, with limited comments, as feedback. The investigators' management was not notified of the score The action plan provided for a Corrective Action Review Board (CARB). This board included the station manager and site vice president, was to meet approximately monthly, and was to review two to four preselected root causes per meeting. IR 50-269,270,287/98-11 reported that the CARB (which was chartered July 1, 1998) had not met monthly and that the station manager and site vice president had not attended the first meeting. The second meeting was attended by the site vice president but not the station manager. In the current inspection, the inspectors found that, in the approximately three months since this item was previously inspected only one additional CARB meeting had been hel That meeting had not been attended by the site vice president or station manager. The minutes of the meeting, held March 1, 1998, indicated that only one root cause analysis had been reviewed and that two planned agenda items had not been discussed because of the lack of key management involvemen The inspectors were familiar with the licensee's investigation of a motor-operated valve problem reported in PIP 1-099-0277. A root cause analysis had been documented for this problem which scored only 8 out of 16 points when graded by licensee root cause coordinators. Based on their knowledge of the investigation and the corrective actions for the problem and on their review of the documented analysis, the inspectors found that the low score was due to reporting deficiencies rather than a poor root cause determination. A licensee root cause coordinator indicated that was a primary reason for low score Conclusion The licensee's implementation of the PIP root cause quality improvement initiative (N9834) was not consistent with the scope and goals for this recovery plan item. The goal for this initiative had not been achieved and important actions specified by the licensee for improvement of root cause quality had not been adequately implemente Direct accountability for low scores and upper management involvement and support for the improvement plan actions were not apparen E8 Miscellaneous Engineering Issues (92903, 92700)
E (Open) LER 50-269/99-01: Emergency (EFW) Feedwater Outside Design Basis Due to Deficient Documentation (Open) Violation (VIO) 50-269, 270, 287/98-15-01: Failure to Update the UFSAR (Open) URI 50-269,270287/99-10-02: 10 CFR 50.59 Evaluations Incorrectly Implemented the EFW Licensing Basis LER 50-269/99-01, dated March 26, 1999, addressed a single failure issue that may not meet the current licensing basis of the EFW system. Inspector in-office review of the LER found that the stated corrective actions adequately addressed the NRC concerns, with EFW system single failure vulnerabilities, that were described in a letter to the
licensee dated February 24, 1999. The NRC concerns with EFW single failure vulnerabilities were also addressed in URI 50-269,270,287/99-10-02. The corrective actions stated in the LER also adequately addressed the NRC concerns, with the accuracy of the UFSAR description of the EFW system safety function, that were described in VIO 50-269,270,287/98-15-01, Example The inspector also noted some statements in the LER that warranted comment. On Page 2 of the LER, the licensee stated that the NRC accepted, in 1973, the use of EFW cross-connects between units to mitigate a main feedwater line break event that could result in the loss of the EFW system and the 4160 volt engineered safeguards switchgear. Although the NRC had acknowledged the capability to use EFW flow from one of the other Oconee units to mitigate this event, the staff's 1973 Safety Evaluation Report on Supplement 1 to Report OS-73.2, "Analysis of Effects Resulting from Postulated Piping Breaks Outside Containment for Oconee Nuclear Station Units 1, 2, and 3," focused on the modification to reroute EFW bypass lines away from the postulated main feedwater line rupture area. This modification would enable use of the EFW system to mitigate the postulated main feedwater line break and would not rely on obtaining EFW from another uni On page 4 of the LER, the licensee stated that the circuitry to close valve C-1 87 on a low upper surge tank (UST) level, to prevent a loss of the EFW pumps' suction source, is single failure proof. However, inspector review of modification ON-32911 noted that the circuitry was installed with a single solenoid to actuate valve C-187. An active failure of this solenoid could cause valve C-1 87 to fail to close on demand. Therefore, the circuitry to close valve C-1 87 on a low UST level may not be fully single failure proo The safety analysis in the LER did not fully address the safety significance of increased reliance on obtaining EFW from another unit to mitigate design basis events. Obtaining EFW from another unit involves use of manual actions in place of automatic actions. The related time delay results in challenging RCS relief and safety valves and feeding a dry steam generator. The safety analysis did not address the increased risk of a steam generator tube rupture or a stuck open RCS safety valv The inspector concluded that LER 50-269/99-01 included adequate corrective actions to address NRC concerns with single failure vulnerabilities of the EFW system and with the accuracy of the UFSAR description of the EFW system safety function. However, the inspector also concluded that the LER was not completely accurate in describing the EFW system licensing basis and design, nor did it address the safety significance of increased reliance on manual actions in place of automatic action These issues remain open pending the completion of the licensee's single failure analysis of the EFW system as described in the LE E Flow Test of Emergency Feedwater Valves 1,2.3 FWD-313 and -314 The inspectors questioned whether the licensee had demonstrated that cross-connect valves 1,2,3 FWD-313 and FDW-314 could pass the flow required for their accident mitigation function. These are manually operated valves that supply emergency feedwater between units in the event of a secondary system line brea The licensee provided completed test procedure TT/0/A/0325/01, Emergency Feedwater Flow Test, which was transmitted to the NRC in a letter dated May 7, 1979. The stated purpose of the test was to demonstrate automatic starting of the interconnected emergency feedwater system and testing of the system for flow stability. Based on their review of the test records with the Unit 1 nuclear engineer and the test coordinator, who were present during the test, the inspectors found that the test had provided design flow through the cross-connect valves to the Unit 1 and to the Unit 3 steam generators. This provided reasonable assurance that the cross-connect valves and associated piping
could pass the flow require E (Open) Inspector Followup Item (IFI) 50-269,270,287/99-10-04: Emergency Operating Procedure Steps Not Written Clearly or in a Consistent Format Inspection Scope (37500, 92903)
The inspectors reviewed this IFI to determine if licensee emergency procedure AP/0/A/1700/25, Standby Shutdown Facility Emergency Operating Procedure, Revision 13, provided adequate guidance, limits, and/or precautions for (1) initiating standby shutdown facility (SSF) reactor coolant (RC) makeup pump flow to the RCP seals; and (2) initiating SSF auxiliary service water (ASW) flow to a dried out once through steam generator (OTSG).
b. Observations and Findings The first question raised by the inspectors involved whether emergency procedure AP/0/A/1700/25 provided adequate limits and/or precautions for reestablishing SSF RC makeup pump flow to the RCP seals if the time limits specified in this procedure were not met. The inspectors reviewed licensee calculation OSC-5372, Maximum Allowed RC Pump Seal Leakage Rate and Maximum Allowed Total Combined RCS Leakage Rate for SSF RC Makeup System Operability, Revision 11. This calculation determined that SSF RC makeup flow to the RCP seals was required to be established within 10 minutes for Unit 1 and within 20 minutes for Units 2 and 3, in order to prevent RCP seal damage during an SSF event. The Unit 1 RCPs (which were supplied by a different pump vendor than Units 2 and 3) had a more restrictive time requirement for reestablishing RCP seal flow than Units 2 and 3. The inspectors noted that the calculation did not address what effect there would be on the RCP seals if it took longer to establish SSF RC makeup flow than the times determined by the calculatio The inspectors reviewed procedure AP/0/A/1700/25, Revision 13, and noted that the procedure provided guidance in one of the first immediate manual actions regarding the time limitations for establishing RCP seal flow. Step 4.1.1 of this procedure stated that if component cooling (CC) and HPI seal injection are lost to the RCPs, then establish RCP seal flow with the SSF RC makeup pump (Unit 1 within.10 minutes; Unit 2 within 20 minutes; and Unit 3 within 20 minutes). The inspectors noted that the procedure did not provide any guidance for establishing SSF RC makeup flow to the RCP seals if the time requirements specified in calculation OSC-5372 and procedure AP/0/A/1700/25 were not met. The inspectors also noted that the procedure did not provide guidance regarding whether the SSF RC makeup flow to the RCP seals should be established at full flow or at a slower flow rate and gradually throttled to full flo The inspectors raised this question as a concern for Unit 1, in that the 10 minute time requirement for establishing SSF RC makeup flow to the Unit 1 RCP seals provided for very little margin. In past walkthroughs and drills, licensee operators had experienced difficulty in meeting the 10 minutes. Inspectors noted that there was a reasonable probability that, during an actual event, operators could take longer than 10 minute Also, the licensee relied in part on use of the SSF to mitigate a tornado event. Inspectors noted that, during a tornado event, operators may well take longer than 10 minutes to go out to the SSF and start the SSF RC makeup pump. The inspectors were concerned that, with no cautions or limits againt doing so, operators could start full SSF RCP seal makeup flow well after 10 minutes and after the RCP seals had been heated up to RCS temperature. Then further RCP seal degradation and/or damage could potentially be caused by cold seal flow chill shocking the hot RCP seals. Consequently, RCP seal leakage could potentially be increasedhocki thehe maximum of 25 gallons per minute assumed in the licensee's accident analysis. The inspectors noted that the licensee's probabilistic risk assessment considered that establishing SSF RC makeup flow to the RCP seals, to limit RCP seal leakage, was one of the most important actions
needed to prevent core damag The inspectors focused on the Unit 1 time requirement during discussions with licensee personnel due to the Unit 1 time being the most limiting. The inspectors noted that there did not appear to be a safety concern if flow is established to the RCP seals within the time limits specified in this procedure. However, neither the procedure nor the licensee's analysis addressed reestablishing RCP seal flow from the SSF if the 10 minute time was exceeded. This question will be reviewed further by the NR The second question raised by the inspectors involved whether emergency procedure AP/0/A/1700/25 provided adequate limits and/or precautions for reestablishing flow to a dry OTSG. The procedure required that flow be established to the OTSGs with the SSF ASW pump within 14 minutes. The procedure did not address what to do if the 14 minute time requirement was not met. There was no guidance regarding whether the SSF ASW flow to the OTSGs should be established at full flow or at a slower flow rate and gradually throttled to full flow in order to prevent possible tube damage due to the colder SSF ASW flow. The inspectors reviewed selected sections of emergency procedure AP/1/A/1700/019, Loss of Main Feedwater, Revision 10; and selected sections of emergency procedure EP/1/A/1800/001, Emergency Operating Procedure, Revision 2 These procedures provided precautions, limits, and guidance for reestablishing feedwater flow to a dried out OTSG. The inspectors noted that procedure AP/0/A/1 700/25 was not consistent with these other emergency operating procedures in that it did not contain the precautions, limits, or guidance for reestablishing flow to a dried out OTSG that was included in emergency procedures AP/1/A/1700/019 and EP/1/A/1800/00 The inspectors discussed this question with licensee personnel who stated that there was a transient at Oconee in August 1994 where an OTSG boiled dry. During that event Unit 3 OTSG 3B was isolated for over seven hours before feedwater flow was reestablished. Prior to the Unit 3 restart from that 1994 event, transient data was evaluated for the 3B OTSG by the vendor, Babcock and Wilcox Nuclear Technologies (BWNT), who determined that the transient did not adversely affect the 3B OTSG. This event was documented in LER 50-287/94-02 and NRC IRs 50-269,270,287/94-24 and 94-28. The inspectors noted that, based on the vendor's analysis of this previous event, there was not a safety concern if SSF ASW flow was initiated to the OTSGs within the time specified in emergency procedure AP/0/A/1700/25. However, the inspectors questioned whether the limits, precautions, and/or guidance in procedures AP/1/A/1700/019 and EP/1/A/1800/001 for reestablishing flow to a dry OTSG should also be incorporated in procedure AP/0/A/1700/25. This question will be reviewed further by the NR The inspectors discussed both these questions with licensee personnel who stated that they had concluded that the guidance in emergency procedure AP/0/A/1700/25 was adequate. The licensee's conclusion was based on calculation OSC-5372 which addressed RC makeup flow to the RCP seals, and the BWNT analysis of the August 1994 transient for the OTSGs. The inspectors informed the licensee that these two questions will be identified for further NRC followup as IFI 50-269,270,287/99-02-05:
Procedure AP/0/A/1 700/25 Guidance for Establishing Flow to the RCP Seals and to a Dry OTSG from the SSF. The inspectors stated to the licensee that IFI 50-269,270,287/
99-10-04 will also remain open for further NRC revie c. Conclusions The inspectors concluded that procedure AP/0/A/1700/25, Revision 13, provided adequate guidance and there did not appear to be a safety concern with regard to re establishing RC makeup flow to the RCP seals and, ASW flow to a dry OTSG from the SSF if the actions are performed within the time requirements specified in emergency procedure AP/0/A/1700/25. However, the inspectors did question the adequacy of the
guidance if the time requirements were not met. An IFI was identified for further followup on these question IV. Plant Support RI Radiological Protection and Chemistry Controls R Radiological Protection (71750)
The inspectors periodically toured the Radiation 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 inspector concluded that radiation control practices were prope R Conduct of Radiological Protection and Controls Inspection Scope (83750, 60855)
The inspectors reviewed personnel monitoring, radiological postings, high radiation area controls, posted radiation dose rates, contamination controls within the RCA, and container labeling. In addition As Low As Reasonably Achievable (ALARA) work planning, prejob worker briefings, and job execution observations were performed. The inspectors also reviewed licensee records of personnel radiation exposure, work activities associated with the loading and transport of spent fuel to the independent spent fuel storage installation (ISFSI) and discussed ALARA program details, implementation and goals. Requirements for these areas were specified in 10 CFR 20 and T b. Observations and Findings The radioactive material storage areas, high radiation areas, and locked high radiation areas were appropriately posted, stored and labeled with one exception. Minor labeling problems for radioactive material were identified in the reactor coolant pump refurbishment building. These items were corrected during the inspectio Operational and administrative controls ensure that workers are knowledgeable of radiation work permits (RWPs) prior to entering the RCA. This is accomplished by the use of computer access terminals that require workers acknowledge understanding of their RWP prior to entry. The inspectors reviewed selected RWPs for adequacy of the radiation protection requirements based on work scope, location, and conditions. For the RWPs reviewed, the inspectors noted that appropriate protective clothing, and dosimetry were require The inspectors physically checked locked high radiation area doors while touring plant areas; reviewed the annual high radiation area key audit, the most recent key inventory, the key issue log, and verified controls for four high radiation area key storage boxe The inspectors found that access to locked high radiation areas was being controlled by the license The inspectors discussed ALARA goals and annual exposures with licensee management and determined the organizational structure and responsibilities for the ALARA staff were clearly defined in organizational charts. The site ALARA program was reviewed in detail and found to include appropriate ALARA outage planning. The inspectors discussed boundary postings and control for the spent fuel that was discharged to the dry storage cask (DSC) and transported to the onsite horizontal storage modules (HSM) and independently verified shielding and measured minimal radiation level The calender year to date (YTD) person-rem total was estimated as 6.9 person-rem. The calendar year site exposure goal was set at 323 person-rem. Records reviewed showed that the licensee was tracking and trending personnel contamination events (PCEs). The licensee had tracked approximately 15 PCEs for the 1999 calender YTD. The inspectors reviewed the contaminated square footage data and observed that the licensee was tracking approximately 1060 square feet or about 0.8 % of the controllable are Conclusions Radiological facility conditions in radioactive material storage areas, health physics facilities, turbine building, and waste storage building except for minor problems in the reactor coolant pump refurbishment building were found appropriate and the areas were properly posted and material appropriately labeled. Personnel dosimetry devices were appropriately worn. Radiation work activities associated with the ISFSI were appropriately planned and doses to workers controlled. Radiation worker doses were being maintained well below regulatory limits, the licensee was maintaining exposures ALARA, and access to locked high radiation areas was being controlle R2 Status of Radiation Protection (RP) Facilities and Equipment R Uncontrolled Radioactive Material in Change Rooms Inspection Scope (71750)
The inspectors toured the plant on March 5, 1999, using IP 71750. The inspectors identified uncontrolled radioactive tools in the auxiliary building change room lockers on Units 1, 2, and b. Observations and Findings The inspectors notified RP personnel after discovering the material in the Unit 1&2 change room personnel lockers. The inspectors were accompanied by the RP personnel to the Unit 3 change room where similar items were also discovered in the lockers. The inspectors were informed by RP management that the Unit 1 &2 change rooms had been inspected and cleaned on February 18, 1999. RP management initiated PIP 0-099 0872, removed the material from the lockers, and surveyed the material and the locker The survey found one of the tools at 200 corrected counts per minute (CCM) (counts above background) and the other tools at 0 to 20 CC UFSAR Section 12.4.3 Facilities and Access Provisions, states in part, "Radioactive material and contaminated equipment associated with plant operations shall be labeled/posted, controlled, and stored within the Restricted Area and/or Owner Controlled Area in accordance with 10 CFR 20 requirements." NSD 507, Radiation Protection, Revision 2, states, "The owner of radioactive material is responsible for maintaining the integrity of the storage container. Do not leave any radioactive material unattended in the RCA unless properly labeled and stored as approved by RP."
Contrary to the above, radioactive material and tools, were unlabeled and left in an un approved location, the change room personnel lockers. 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 50-269,270,287-99-02-06, Uncontrolled Radioactive Material in Unit Change Rooms. This violation is in the licensee's corrective action program as PIP 0-099-087 Conclusions The failure to properly control storage of radioactive material in the change room personnel lockers was identified as a non-cited violatio *
R Environmental and Process and Effluent Radiation Monitors Inspection Scope (84750, 86750)
The inspectors reviewed selected licensee procedures and records for required surveillances on the radiological environmental monitors, and the process and effluent radiation monitor b. Observations and Findings During tours of the auxiliary building, radwaste building, turbine building and radioactive waste treatment building, the inspectors observed the physical operation of process radiation effluent monitors (EMFs) in service. The inspectors took independent smears and verified that areas were appropriately posted. The inspectors reviewed selected radiation and process monitor surveillance procedures and records for performance of channel checks, source checks, channel calibrations, and channel operational tests. The inspectors found the surveillance performance met TS requirement The inspectors reviewed selected licensee procedures and records for required surveillance of the radiological environmental monitors and verified operability of three of the environmental monitoring stations in the vicinity of the plant. There were no problems observe Conclusions The inspectors concluded radiation and process effluent monitors and environmental monitors were being maintained in an operational condition in compliance with TS requirements and UFSAR commitment R External and Internal Dosimetry Equipment a. Inspection Scope (83750)
The inspectors reviewed the use of electronic digital alarming dosimeters for external exposure control and whole body counting (WBC) equipment for internal exposure contro b. Observations and Findings The inspector observed a demonstration of the remote automatic electronic dosimeter calibration process and verified that the licensee program includes periodic calibration of these instruments. The inspector also reviewed the thermoluminescence and electronic dosimeter (TLD/ED) correlation ratio history and found that a positive 20% bias limit was met. Based on direct observation the ED was being worn by workers entering the RC The inspectors observed the WBC equipment operation, reviewed a one-year history of daily energy alignment quality control checks and annual verification calibration for 1997 and 1998. The inspector found the daily checks demonstrated instrument operability and the annual calibrations were within 10% of the original 1991 WBC calibratio Approximately five internal dose assessments were performed for 1998 based on WBC bioassay results. The inspector reviewed three 1998 internal dose assessments and verified that the critical organs, dose conversion factors used, and the resulting committed effective dose equivalent calculations were correc Conclusions The inspectors concluded that EDs were being calibrated as required and that intemal assessment of individual intakes of radioactive material met regulatory requirement R7 Quality Assurance in Radiation Protection and Chemistry R Audits and Self-Assessments Inspection Scope (83750, 84750, 86750)
Licensee quality assurance activities and self-assessment programs were reviewed to determine the adequacy of identification and corrective action programs for deficiencies in the area of chemistry and health physic b. Observations and Findinqs Reviews by the inspectors determined that quality assurance audits and self-assessment efforts in the areas of chemistry and RP were accomplished by reviewing chemistry and RP procedures, observing work, reviewing industry documentation, and performing plant walk-downs to include surveillance of work areas by supervisors and technicians during normal work coverage. Documentation of problems by licensee representatives were included in quality assurance audits and self-assessment report The inspectors found the nuclear assurance reports and job observations insightful, and detailed. Identified items were trended, tracked, and closeout was determined to be timel Conclusions The inspectors determined the licensee was conducting formal RP and chemistry audits as required by TS and conducting self-assessments. The licensee was developing corrective action plans, trending, and completing corrective actions in a timely manne S1 Conduct of Security and Safeguards Activities S General Comments (71750)
During the period, the inspectors toured the protected area and noted that the perimeter 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 April 15, 1999. The licensee acknowledged the findings presented. No proprietary information was identified to the inspector The NRC comments on LER 50-269/99-01 that are documented in Section E8.1 were discussed by telephone on May 4, 1999, between R. Schin of the NRC and E. Burchfield of the licensee. The licensee did not agree with the NRC interpretation that the EFW system licensing basis did not rely on obtaining EFW from another unit to mitigate a main feedwater line break. As stated in the LER, the licensee plans to clarify the EFW licensing basis to resolve conflict with the NRC staff positio X2 Pre-Decisional Enforcement Conference Summary On January 26, 1999, a predecisional enforcement conference was held in the Regional Office with the licensee to discuss apparent violations (EEl) 50-269,270,287/98-15-02 and EEl 50-269,270,287/98-15-03, covered by EA Case No.98-552. Following the conference, a Notice of Violation (NOV) was issued to the licensee on February 12, 1999, for apparent violations EEl 50-269,270,287/98-15-02 and EEl 50-269,270,287/98-15-0 The first violation cited in the NOV will be tracked as EA 98-552-01014, Emergency Procedure Not Adequate to.Mitigate Secondary Pipe Break Events. The violation was characterized at Severity Level IV. The second violation cited in the NOV will be tracked as EA 98-552-02014, inadequate 10 CFR 50.59 Safety Evaluations. The violation was also characterized at a Severity Level IV. Based on the above, both EEls are now considered close X4 NRC Management Review Meeting of Open Items The NRC recently revised NUREG-1600, Rev. 1, "General Statement of Policy and Procedures for NRC Enforcement Actions," (Enforcement Policy) by the addition of Appendix C. Appendix C, Interim Enforcement Policy for Power Reactor Severity Level IV Violations, effective March 11, 1999, revises the NRC's enforcement approach for Severity Level IV violations. Appendix C permits closure of most Severity Level IV violations, based on the violation being entered into the licensee's corrective action program, as well as other considerations as described in the Appendix. The NRC conducted a review of the following Severity Level IV violations, and considers it appropriate to close these violations consistent with Appendix C of the Enforcement Policy:
Violation Number Corrective Action Program File Number 50-269,270,287/98-11-10 PIP 0-098-1807 50-269,270,287/98-10-05 PIP 0-098-124 50-269,270,287/98-09-02 PP00842 50-269,270,287/98-06-10 PIP 4-098-3206 50-270/98-06-09 PIP 0-098-3442 50-270/98-06-08 PIP 0-098-2850 50-269/98-06-06 PIP 1-098-2858 50-269,270,287/98-06-01 PIP 2-098-2679 50-269/98-02-05 PIP 1-098-0937 50-270/98-02-03 PIP 0-098-1786, 2-098-0691 50-269,270,287/97-18-05 PIP 3-098-0232 50-269,270,287/97-16-09 PIP 4-097-4406 50-269,270,287/97-14-10 PIP 1-097-3183 50-287/97-12-05 PIP 3-097-2730 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 0. 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 B. Millsaps, Rotating Equipment Manager Other licensee employees contacted during the inspection included technicians, maintenance personnel, and administrative personne NRC D. LaBarge, Project Manager Inspection Procedures Used IP37550 Engineering IP37551 Onsite Engineering IP40500 Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP61726 Surveillance Observations IP62707 Maintenance Observations IP60855 Operation of an ISFSI IP71707 Plant Operations IP71750 Plant Support Activities
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IP83750 Occupational Radiation Exposure IP84750 Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP86750 Solid Radioactive Waste Management and Transportation of Radioactive Materials IP92700 Onsite Followup of Written Event Reports IP92901 Followup - Operations IP92903 Followup - Engineering IP93702 Prompt Onsite Response to Events Items Opened, Closed, and Discussed Opened 50-269,270,287/99-02-01 NCV Failure to Follow Overtime Procedure (Section 08.2)
50-270/99-02-02 NCV Failure to Follow Procedure for Valve and Pump Operation - Two Examples (Section 08.3)
50-269,270,287/99-02-03 NCV Failure to Provide Adequate Valve Replacement Design Control (Section 08.3)
50-270/99-02-04 NCV Failure to Take Prompt Corrective Actions - Two Examples (Section 08.3)
50-269,270,287/99-02-05 IFI Procedure AP/0/A/1700/25 Guidance for Establishing Flow to the RCP Seals and to a Dry OTSG from the SSF (Section E8.3)
50-269,270,287/99-02-06 NCV Uncontrolled Radioactive Material in Unit Change Rooms (Section R2.1)
EA 98-552-01014 VIO Emergency Procedure Not Adequate to Mitigate Secondary Pipe Break Events (Section X2)
EA 98-552-02014 VIO Inadequate 10 CFR 50.59 Safety Evaluations (Section X2)
Closed 50-287/97-04-00 LER Deficient Procedure Results in a Missed Technical Surveillance Check (Section 08.1)
50-269,270,287/98-11-03 URI Overtime Procedures and Controls (Section 08.2)
50-269,270,287/98-06-04 URI Unit 2 Valve Misposition Issues (Section 08.3)
50-269,270,287/98-15-02 EEl Inadequate 10 CFR 50.59 Safety Evaluations (Section X3)
50-269,270,287/98-15-03 EEl Emergency Procedure Not Adequate to Mitigate Secondary Pipe Break Events (Section X3)
50-269,270,287/98-11-10 VIO Failure to Properly Implement Procedural Requirements for a Continuous Fire Watch (Section X4)
50-269,270,287/98-10-05 VIO Inadequate Corrective Action Concerning Removal of Lagging Adhesive from Stainless Steel Piping and Components (Section X4)
50-269,270,287/98-09-02 VIO No QA Records to Assure the Ability of EFW Pumps to Operate at Run Out (Section X4)
50-269,270,287/98-06-10 VIO Failure to Follow Radiation Protection Procedure (Section X4)
50-270/98-06-09 VIO Failure to Perform Safety Evaluation for COLR Change (Section X4)
50-270/98-06-08 VIO Failure to Complete Procedure Following SSW Modification (Section X4)
50-269/98-06-06 VIO Failure to Follow Procedures During ES Testing (Section X4)
50-269,270,287/98-06-01 VIO Failure to Establish a Procedure for Adjusting RCP Restraints (Section X4)
50-269/98-02-05 VIO Failure to Follow Minor Modification Process (Section X4)
50-270/98-02-03 VIO Failure to Follow Temporary Modification Process (Section X4)
.
50-269,270,287/97-18-05 VIO Failure to Revise Procedure Following ICS Modification (Section X4)
50-269,270,287/97-16-09 VIO Failure to Follow Procedure for Contamination Control (Section X4)
50-269,270,287/97-14-10 VIO Inadequate Radiation Protection Posting and Controls (Section X4)
50-287/97-12-05 VIO Failure to Remove Protective Clothing (Section X4)
Discussed 50-269/99-01 LER Emergency Feedwater Outside Design Basis Due to Deficient Documentation (Section E8.1)
50-269,270,287/98-15-01 VIO Failure to Update the UFSAR (Section E8.1)
50-269,270,287/99-10-02 URI 10 CFR 50.59 Evaluations Incorrectly implemented the EFW Licensing Basis (Section E8.1)
50-269,270,287/99-10-04 IFI EOP Steps Not Written Clearly or in a Consistent Format (Section E8.3)
List of Acronyms AC Alternating Current ALARA As Low As Reasonably Achievable ASW Auxiliary Service Water BWNT Babcock and Wilcox Nuclear Technologies CARB Corrective Action Review Board CC Component Cooling CCM Corrected Counts per Minute CFR Code of Federal Regulations CIT Continuous Improvement Team DBD Design Basis Document DC Direct Current DP Differential Pressure DSC Dry Storage Cask EEI Apparent Violation ED Electronic Dosimeter EFW Emergency Feedwater EHC Electro-Hydraulic Control EMF Radiation Effluent Monitor ESF Engineered Safety Feature EWST Elevated Water'Storage Tank HPI High Pressure Injection HPSW High Pressure Service Water HSM Horizontal Storage Modules IFI Inspector Followup Item IP Inspection Procedure IR
Inspection Report
Independent Spent Fuel Storage Installation
KHU
Keowee Hydro-Electric Unit
KV
Kilovolt
LER
Licensee Event Report
Low Pressure Service Water
Non-Cited Violation
NRC
-Nuclear Regulatory Commission
NSD
Nuclear Site Directive
Once Through Steam Generator
Problem Investigation Process
Post-Modification Test
Personnel Contamination Events
PSID
Pounds per Square Inch Differential
Pounds per Square Inch Gauge
RC
Radiation Control Area
Reactor Coolant Pump
Radiation Protection
Radiation Work Permits
Selected Licensee Commitment
SSF
Standby Shutdown Facility
Siphon Seal Water
Thermoluminescence Dosimeter
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
UST
Upper Surge Tank
Violation
Whole Body Counting
Work Order
YTD
Year To Date