IR 05000269/1998009
| ML15261A370 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 11/13/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15261A368 | List: |
| References | |
| 50-269-98-09, 50-269-98-9, 50-270-98-09, 50-270-98-9, 50-287-98-09, 50-287-98-9, NUDOCS 9812010235 | |
| Download: ML15261A370 (42) | |
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 No:
50-269/98-09, 50-270/98-09, 50-287/98-09 Licensee:
Duke Energy Corporation Facility:
Oconee Nuclear Station, Units 1, 2, and 3 Location:
7812B Rochester Highwa Seneca, SC 29672 Dates:
September 6 - October 17, 1998 Inspectors:
M. Scott, Senior Resident Inspector D. Billings, Resident Inspector E. Christnot, Resident Inspector S. Freeman, Resident Inspector J. Blake, Regional Inspector (Section M8.1)
F. Jape, Regional Inspector (Sections 08.4-08.6, M8.2-M8.6, E8.6-E8.12)
R. Moore, Regional Inspector (Sections E2.2, E2.5, E2.6, E8.5)
B. Schin, Regional Inspector (Sections E7.2, E8.2, E8.3, E8.4)
W. Stansberry, Regional Inspector (Sections S2, S4, S6, S7, S8)
M. Thomas, Regional Inspector (Sections E2.3, E2.4)
.J. Lenahan, Regional Inspector (Section E2.1)
Approved by:
C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects Enclosure 2 9812010235 981113 PDR ADOCK 05000269 PDR
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2, and 3 NRC Inspection Report 50-269/98-09, 50-270/98-09, and 50-287/98-09 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspection, and the results of announced inspections by seven Region-based inspectors. [Applicable template codes and the assessment for items inspected are provided below.]
Operations
Unit 3 reduced inventory operations were completed properly with appropriate operator action, good supervisory oversight, and good procedure adherence. (Section 01.2;
[POS: 1A, 3A, 3C - Good])
The licensee has effectively responded to operational concerns in the areas of work planning, control room noise, and response to out-of-service control room indicators (Recovery Plan Item OF3 - Closed). (Section 01.3; [POS: 1A, 3C - Good])
The lack of a calculation for operation of the reactor building spray system with suction from the borated water storage tank resulted in an operable, but degraded, syste (Section 02.4; [NEG: 4A - Poor])
The operability evaluation and compensatory measures for degraded operation of the reactor building spray system with suction from the borated water storage tank addressed relevant safety concerns. (Section 02.4; [POS: 4B, 5C - Adequate])
The management and reduction of workable Control Room Instrument Problems met the Recovery Plan goals. The philosophy change to ensure control room instruments received increased awareness and timely repair was good (Recovery Plan Item SE7 Closed). (Section 02.5; [POS: 1A, 2B, 3C - Good])
The licensee has adequately reviewed recent control rod mobility problems. Historically, this review process has been ongoing. The licensee plans to replace the mechanisms over the three series of refueling outages (Recovery Plan Item SE2). (Section 02.6;
[POS: 4B, 5B - Adequate])
A direct current ground on the safety-related power supply for all three units was resolved prior to a critical evolution (i.e., the Unit 3 refueling drain to mid reactor coolant loop level). Licensee management placed the drain down on hold until the ground was found. (Section 02.7; [POS: 2B, 5A, 5C - Good])
A direct current ground on the safety-related power supply for all three units resulted from a failed cable, induced from repair work on a valve. (Section 02.7; [NEG: 2A, 3A Poor])
Licensee actions in resolution of a March 1997 control rod drive short circuit induced reactor trip were adequate. (Section 08.1; [POS: 5C - Adequate])
The corrective actions for the implementation of Lee Station procedures and Keowee lockout instructions were appropriate and the overall actions taken by the licensee were good. (Section 08.2; [POS: 58, 5C - Good])
.
The investigative report regarding the failure to perform an operability test of a 4160 volt breaker was thorough and the corrective actions to prevent recurrence presented in the response letter were adequate. The immediate actions were timely and the long-term actions have been completed. (Section 08.3; [POS: 5B - Good, 5C - Adequate])
The licensee's actions to resolve a potential for not meeting a reactor coolant system Technical Specification temperature limit were complete and thorough. (Section 08.4;
[POS: 5B, 5C - Good])
Maintenance
The licensee carefully followed procedure and used good parts control during the seal injection of the Unit 2 steam generator feedwater risers. (Section M1.2; [POS: 2B Good])
The database specified in the fluid leak management program directive was not yet fully developed. However, the fluid leak management program directive, catch containers, and database tools met the objective of the Oconee Recovery Plan (Recovery Plan Item SE5 - Closed). (Section M2. 1; [POS: 2B - Adequate])
The licensee identified failure to include adequate guidance for eddy current analysts and the failure to correctly analyze eddy current data resulted in a non-cited violation for returning steam generators to service with defective tubes. (Section M8.1; [POS: 5A, 5B, SC - Adequate; NCV: 2A, 2B - Poor])
The analysis and resolution of several examples concerning inadequate control of modifications was timely and thorough. (Section M8.2; [POS: 5B, 5C - Good])
Actions taken by the licensee regarding full thread engagement on packing retaining nuts were timely and complete. (Section M8.3; [POS: SB, SC - Good])
The licensee's analysis of the failure to add an in-service test for the Keowee guide bearing oil system valves resulted in a self-initiated, broader review of problems with the surveillance scheduling process. Resolution of the specific issue was timely and appropriate. (Section M8.5; [POS: 5B, 5C - Good])
The corrective actions taken by the licensee regarding a violation for the failure to establish and implement procedures were timely and thorough. (Section M8.6; [POS:
5B, 5C - Good])
Engineerinq
The licensee's walkdown inspections of coatings were adequate to plan and prioritize coating repair activities to be performed during the current refueling outage. The licensee's actions to address repairs to the coatings in the Unit 3 reactor building were performed in accordance with good engineering practices and NRC requirements (Recovery Plan Item NRC5). (Section E2.1, [POS: 4A, SB - Good])
Implementation of the system team development initiative was consistent with the scope, and schedule described in the Oconee Recovery Plan. The goals were not fully met in that the licensee identified team member attendance and meeting scope as an area for improvement. However, appropriate self-assessment action was provided to monitor continuing performance related to this initiative which demonstrated the licensee was
adequately addressing these deficiencies (Recovery Plan Item SE4 - Closed).
(Section E2.2; [POS: 4B - Adequate])
Implementation of the temporary modification (TM) initiative was consistent with the scope, schedule, and goals described in the Oconee Recovery Plan. The actions taken by the licensee to reduce the number of old TMs and control the installation of new TMs were effective and contributed to the number of TMs being reduced from greater than 70 in January 1998 to 38 in September 1998 (Recovery Plan Item SE6 - Closed). (Section E.2.3; [POS: 4B,4C - Good])
Implementation of the secondary system/component reliability initiative was consistent with the scope, schedule, and goals of the Oconee Recovery Plan. The actions taken by the licensee had resulted in increased engineering involvement and plant management attention to secondary system component problems. Recommendations from an engineering analysis of selected systems and components were being incorporated into the licensee's work control process (Recovery Plan Item SE9 - Closed). (Section E2.4;
[POS: 2C, 4B - Good])
The implementation of the engineering-operations-maintenance interface item was consistent with the scope, schedule, and goals described in the Oconee Recovery Pla Initial results indicated that the engineering interface with the plant was improved (Recovery Plan Item TD4 - Closed). (Section E2.5; [POS: 4B - Good])
It was not evident that the post-modification/maintenance testing process program improvements have yet assured that all post-modification/maintenance testing are correctly designated, scheduled, and executed which was the stated goal for this recovery plan item (Recovery Plan Item TD6). (Section E2.6; [NEG: 4B - Poor])
A temporary measure of increased pre-outage support by the licensee's implementation team identified a number of outage related post modification/maintenance testing problems which prevented the occurrence of post modification/maintenance testing deficiencies during those outages (Recovery Plan Item TD6). (Section E2.6; [POS: 2B, 5A - Good])
An operating experience feedback process is in effect, being used by applicable personnel, and is considered good (Recovery Plan Item NRC2 - OEF Portion Closed).
(Section E7.1; [POS: 1C, 4C - Good])
The licensee's Safety System Engineering Audit of emergency feedwater was weak in that it did not identify three potentially significant design vulnerabilities, one violation, and some inaccurate Updated Final Safety Analysis Report statements that were identified by the NRC (Recovery Plan Item DB9). (Section.E7.2; [NEG: 5A - Poor])
The root cause analyses for two relay failures were excellent in that they were very thorough, comprehensive, technically sound, and identified the most probable cause of the failures. (Section E8.1; [STREN: 4B, 58, 5C - Excellent])
A violation was identified for inadequate design control in that there were no quality records of tests or analyses to assure the ability of the emergency feedwater pumps to operate at runout as relied upon to mitigate a design basis accident since 1986. Also, the licensee had missed two recent opportunities to identify this violation (Recovery Plan Item DB9). (Section E8.2; [VIO: 4A, 5A - Poor])
- .
The tracer gas tests of the control room ventilation system represented a substantial improvement in the licensee's ability to assure operability (Recovery Plan Item NRC3).
(Section E8.3; [POS: 4B, 2B - Good])
The licensee's Updated Final Safety Analysis Report (UFSAR) Review Project failed to identify several inaccurate statements in the UFSAR. Specifically, an unresolved Item concerning inaccurate emergency feedwater (EFW) system information in the UFSAR was opened to followup on whether the NRC relied upon this information in approving the licensee's EFW system design (Recovery Plan Item DB5). (Section E8.4; [URI:
4A, 4C, 5A - Poor])
The licensee's actions for Generic Letter 96-06 were consistent with the scope, goals, and schedule described in the Oconee Recovery Plan. Outstanding actions are appropriately tracked via a licensee event report and supplemental responses to Generic Letter 96-06 (Recovery Plan Item DB8 - Closed). (Section E8.5; [POS: 4A Adequate])
The analysis and resolution of a problem with the emergency feedwater recirculation valve was thorough and satisfactory. (Section E8.6; [POS: 5B, 5C - Adequate])
The analysis and resolution for a violation concerning an inadequate engineering evaluation for lifts over safety-related components was complete and timely. (Section E8.7; [POS: 5B, 5C - Good])
Once the issue of not reviewing test results was identified, the licensee promptly performed an investigative report. The analysis and resolution were complete and timely. (Section E8.8; [POS: 5B, 5C - Good])
The licensee's analysis and resolution for failure to update the Updated Final Safety Analysis Report regarding fuel enrichment was thorough and timely. (Section E8.9;
The licensee's analysis and resolution concerning a failure to assure that the design basis for valves in the Unit 1, 2, and 3 letdown storage tank instrument lines were correctly translated into station procedures was timely and complete. (Section E8.10;
[POS: 5B, 5C - Good])
The licensee initiated a design study report to resolve ground issues. The study was thorough and made several recommendations which were adopted. (Section E8.1 1;
[POS: 5B, 5C - Good])
The licensee's engineering, analysis, and resolution of an error in the energy deposition factor for determining operational imbalance limits was thorough and well done. (Section E8.12; [STREN: 4B, 5B, 5C - Excellent])
Plant Support
The licensee's security facilities and equipment were determined to be reliable and effectively maintained. Good maintenance support was the major factor to continued operability of the personnel search equipment and vehicle barrier system. (Section S2
[POS: 1C, 2A, 3A - Good])
- The security force personnel possessed appropriate knowledge to carry out their assigned duties and responsibilities, including response procedures, use of deadly force, and armed response tactics. (Section S4; [POS: 1C, 3B - Good])
Site and security management provided good support to the Physical Security Progra (Section S6; [POS: 1C, 3C - Good])
The last safeguards audit was thorough, complete, and effective in uncovering weaknesses in the security system, procedures, and practices. (Section S7; [POS: 5A, 5C - Good])
Report Details Summary of Plant Status Unit 1 began and ended the period at 100 percent powe Unit 2 began and ended the period at 100 percent powe Unit 3 began the period at 83 percent power in coastdown to a refueling outage. The unit was shutdown on October 10 from 48 percent power after 362 days of operatio I. Operations
Conduct of Operations 0 General Comments (71707, 71750)
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 The inspectors observed the Unit 3 shutdown. The shutdown was performed with good operator communications, control by shift supervision, use of appropriate procedures, and management oversight. The inspectors also observed the actions of the designated building spray operator (BSO) during the shutdown. The actions of the BSO were in accordance with the operations directiv.2 Unit 3 Drain for Nozzle Dam Installation a. Inspection Scope (71707)
On October 16, 1998, the licensee drained the Unit 3 reactor coolant system (RCS) to reduced inventory conditions in order to install nozzle dams for maintenance work on the once through steam generators (OTSG). The inspectors observed the reduced inventory activitie b. Observations and Findinqs The licensee entered reduced inventory operations when the operators reduced the RCS level to less than 50 inches above the centerline of the hot legs. The inspectors attended the pre-job briefing and were present in the control room during draining operations until the RCS level stabilized at 19 inches above the centerline of the hot leg The inspectors observed that licensee controls of electrical power, containment closure, RCS level indication, exit thermocouples, RCS makeup capability, and RCS vent path met licensee procedural and regulatory requirement The inspectors also observed the operators routinely referring to their procedure and careful oversight by both senior reactor operators and licensee managemen c. Conclusions Unit 3 reduced inventory operations were completed properly with appropriate operator action, good supervisory oversight, and good procedure adherenc.3. Prompt Response to Operational Concerns (Recovery Plan Item OF3)
a. Inspection Scope (71707)
The inspectors interviewed personnel, reviewed records, and observed control room and work control center activitie b. Observations and Findings The Response to Operational Events (OF3) initiative was changed in the licensee's program in March 1998. This initiative was split into initiatives for the Top Equipment Problem Resolution (TEPR), Operations/Chemistry interface, and Work Management process improvement. These initiatives are ongoing under separate inspection activitie The focus of the original initiative was to ensure operator concerns were effectively responded to. The inspectors verified that: noise and activity levels in the control room have decreased, leading to improved operator attention to the control room indicators; out-of-service control room indicators are being identified and given priority for correction; and planning and scheduling of work schedules have been improved due to the involvement of a senior reactor operator in the work control center and the work control process. Licensee management has increased the focus on response to operational issues. The inspectors verified the increased focus through interviews and direct observation. Based on the above observations and the fact that other initiatives are in place, this initiative is close Conclusions The inspectors concluded that the licensee has effectively responded to operational concerns in the areas of work planning, control room noise, and response to out-of service control room indicators. Recovery Plan Item OF3 is close Operational Status of Facilities and Equipment 0 Operations Clearances (71707)
The inspectors reviewed the following clearances during the inspection period:
98-3743, Keowee Hydro Unit (KHU)-2 Governor Actuator
98-3760, KHU-2 Generator The inspectors observed that the clearances were properly prepared and authorized, and that the tagged components were in the required positions with the appropriate tags in plac.2 Containment Isolation Lineup (71707)
The inspectors reviewed the following portions of the containment isolation lineup during the inspection period:
Unit 1, 2, 3 valves controlled from the standby shutdown facility (SSF)
The inspectors observed that the lineup was in accordance with plant operating procedures and the Updated Final Safety Analysis Report (UFSAR).
0 Engineered Safety Feature (ESF) System Walkdown (71707)
The inspectors walked down accessible portions of the following ESF systems:
Keowee Unit 1
Unit 1 Component Cooling System
Unit 1, 2, and 3 Condenser Circulating Water 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.4 Reactor Building Spray (RBS) Pump Net Positive Suction Head (NPSH)
a. Inspection Scope (71707, 37551, 93702)
On October 1, 1998, the licensee made a 10 CFR 50.72 notification regarding the RBS pumps for all three units being in a condition outside the design basis for the plant. The inspectors reviewed the circumstances surrounding this notificatio b. Observations and Findings On September 28, 1998, as part of a followup of a corrective action for a Self-Initiated Technical Audit (SITA) regarding the low pressure injection (LPI) and high pressure injection (HPI) systems, the licensee discovered there was no calculation of record for operation of the RBS with the suction aligned to the borated water storage tank (BWST)
following a loss of coolant accident (LOCA). Upon reconstitution of the calculation, the licensee learned that NPSH available to the RBS pumps was inadequate to prove operability of the pumps after 5-8 minutes of operation. The licensee instituted compensatory measures to dedicate one operator in each control room to throttle the flow on each RBS pump immediately upon actuation of the RBS following a LOC The inspectors reviewed the 10 CFR 50.72 notification, the operability evaluation, and associated problem identification process report (PIP) 0-98-4512. The inspectors also attended the Plant Operations Review Committee (PORC) meeting that approved the compensatory measures. The inspectors found that the licensee appropriately detected the inadequate NPSH and reported it in a timely manner. The operability evaluation was conservative in that it was based on a system flow rate that would occur with no pressure in the containment. The PORC addressed relevant safety concerns regarding the compensatory measures, including: procedures, training of operators, and description of
dedicated operator duties. The NRC will continue to follow this issue, including any non compliance with NRC regulations, under Licensee Event Report (LER) 50-269/98-12:
RBS NPSH Inadequate for Injection Mod Conclusions The lack of a calculation for operation of the reactor building spray system with suction from the borated water storage tank resulted in an operable, but degraded, syste The operability evaluation and compensatory measures for degraded operation of the reactor building spray system with suction from the borated water storage tank addressed relevant safety concern.5 Control Room Instrument Problem (CRIP) Management and Reduction (Recovery Plan Item SE7)
a. Inspection Scope (71707)
The inspectors reviewed Recovery Plan goals and initiatives, interviewed responsible managers, and verified items being tracked under the CRIP reduction initiativ b. Observations and Findinqs The licensee's Recovery Plan listed CRIP reduction and management as an initiative to ensure out-of-service control room instruments received the appropriate level of revie The Recovery Plan goal was to have total workable CRIPs less than 15 total for the three units with none greater than 2 months ol In December 1997, the total workable CRIPs stood at 44. In February 1998, the philosophy was changed to treat all CRIPs as Priority E work orders (highest urgency level). This means that all CRIPs would be scheduled for work within four weeks. In May 1998, the total workable CRIPs were reduced to 23, but increased to 34 following the Unit 2 outage. From July 1998 up to the September 1998 licensee data base update, total workable CRIPs have remained below 1 In September, new instructions were promulgated to identify all items needing repair as Control Board Work Orders (CBWO). Only those items that represent actual instrument problems are now designated as CRIPs. The instructions also list responsibilities for the review, addition, and deletion of CBWOs for the control room personnel and for the Unit Coordinators. The CBWO and CRIP list is reviewed Monday through Thursday by a team consisting of operations, planning, and scheduling personnel to verify workable and outage related CBWO The licensee has changed the initiative status to green in the Recovery Plan based on reaching the goal of less than 15 CRIPs. The inspectors have reviewed the documentation in the Recovery Plan, reviewed the actual completion of the control room work items, and have discussed the CRIP management plan with those individuals involved. Based on meeting the Recovery Plan goal and review of the program, this initiative is close Conclusions The inspectors concluded that the management and reduction of workable Control Room Instrument Problems met the Recovery Plan goals. The philosophy change to ensure control room instruments received increased awareness and timely repair was goo Recovery Plan Item SE7 is close.6 Units 1 and 3 Control Rod Mobility Problem Reviews (Recovery Plan Item SE2 a. Inspection Scope (93702)
During the last two inspection periods, the licensee has identified examples of slowed control rod motions (Unit 1 return to power and the Unit 3 refueling shutdown). This had been seen previously and the licensee initiated actions to control the impact of the problems. The inspectors observed trip testing and control rod group manipulations, reviewed evaluations, and talked with licensee management about the result b. Observations and Findinqs Due to wear and crud buildup in control rod drive mechanisms, the licensee has seen random instances of control rod mobility degradation. However, the recently observed changes (i.e., slow rod times and lagging control rods) have yet to result in an inoperable control ro Slow Rod Trip Times During trip time tests, the following control rods were slower than the licensee's established administrative limit of 1.40 seconds. The control rods and times were as follows:
Unit 1 Group 3, Control Rod 6 1.44 seconds PIP 1-98-4067 Group 6, Control Rod 5 1.56 seconds PIP 1-98-4067 Licensee evaluation of the control rod problems was acceptable. The control rod times were well below their Technical Specification (TS) limit of 1.66 seconds. The Unit 1 evaluation initially omitted a discussion of the importance of a statistical study done by the licensee that more fully supported the conservative nature of the evaluation. This topic was presented to the NRC during a telephone conversation with the supporting documentation. On an as required basis, the licensee has been changing out the thermal barriers in response to the slower than predicted control rod drop times. This
.
has been done to preclude the affect that crud build up in the barriers has on rod drop times. With regard to slow control rods, a search of historical problem reports by the inspectors revealed no negative trends to date after barrier change out Laqqinq Control Rods During control rod group manipulations, the licensee has experienced problems with control rod motion in that certain control rods were lagging behind their group in positive or outward group height changes. These control rods were:
Unit 1 Group 5, Control Rod 7 PIP 1-98-4098 Unit 3 Group 7, Control Rod 5 PIP 3-98-4604 The associated evaluations were technically satisfactory. Both recent write ups recognized that this has occurred before (i.e., 1995) and that crud buildup internal to the drive mechanism had been the most likely root cause for the problem. The crud most probably causing this type of problem potentially comes from trip ratchet fines, which are relatively large and differentiated from the systemic suspended solids present in the thermal barriers. This problem left the control rods difficult to drive incrementally outward with their group, but still capable of being tripped without any attendant control rod drop time increase and without any latching problems. With regard to lagging control rods, a historical problem report search by the inspectors revealed no negative trend to dat These recent lagging control rod problems are approximate in time to one another but did not represent a trend or pose safety issues. To date, based on the review, lagging outward motion and slow control rod drop times have not been experienced on the same control ro The licensee is to begin a change out of the entire control rod drive mechanisms (CRDM) starting with Unit 1 in June of 1999. The change out will be done in thirds taking a full three refueling outages per unit. Based on outage schedule, up to ten CRDMs may be available for further replacements. The first CRDMs to be selected for replacement will be those CRDMs that had experienced previous problems. This action plan was recently reviewed (October 8, 1998) by the licensee, and, as indicated above, no negative trends were observed that caused them to consider a drive replacement rate change. The licensee was carefully monitoring the condition of control rods. Due to the required dynamic response of these normally static components, this close scrutiny is warrante Conclusions The licensee has adequately reviewed recent control rod mobility problems. Historically, this review process has been ongoing. The licensee plans to replace the mechanisms over the three series of refueling outage.7 Direct Current Grounds a. Inspection ScoDe (71707)
On October 10, 1998, during the beginning of the Unit 3 refueling outage, the safety related batteries that are normally cross-tied between all three units developed a hard ground. The inspectors followed the investigation and repair activities. The inspectors also reviewed the applicable TS 3.7 and Selected Licensee Commitment (SLC)1 b. Observations and Findings The licensee began ground investigation activities in accordance with site procedures that are impacted by the six-day time constraint of SLC 16.8 action statement. By day four of the statement constraint, the licensee had made little headway finding the groun Site management changed the focus of the investigation and escalated efforts. The ground resolution went from a day shift activity to around-the-clock. Conservatively, site management placed a planned drain down of the Unit 3 primary on hold until the ground problem was resolved. On day five of six, the ground was located and isolate Subsequently, the action statement condition was exited. The ground was present just prior to the unit shutdown from work performance on air operated valve 3PR-2. A slit in the control power cabling to the valve was determined to be the source of the groun No electrical work was performed just prior to ground detection, but the cabling may have been agitated to initiate the ground. The inspectors were present through the troubleshooting and ground identification, finding the licensee activities properly conservativ Conclusions A direct current ground on the safety-related power supply for all three units was resolved prior to a critical evolution, the Unit 3 refueling drain to mid reactor coolant loop level. Management placed the drain down on hold until the ground was found. The ground was from a failed cable, induced from repair work on a valv. 08 Miscellaneous Operations Issues (92901, 92700, 90712)
0 (Closed) LER 50-287/97-01: Control Rod Drive System Short Circuit Results in a Reactor Trip Due to a Manufacturing Deficiency The Unit 3 reactor tripped on March 20, 1997, from 73 percent power due to a wiring short on a relay for the trip circuitry in conjunction with trip circuitry testing. A short developed in a relay for the opposite train of the trip circuitry while testing was ongoin The plant trip response was normal with no significant problem The root cause of the event was attributed to a manufacturing deficiency in an electrical plug within the circuitry. The plug was replaced, the indicator light was repaired, fuses were replaced and verified to be the correct size, and the procedure was changed to verify no blown fuses existed prior to testing. The inspectors verified that the procedure changes were in effect and observed verification of the fuses prior to testing. No new information was revealed. The Inspector Followup Item (IFI) 97-01-01 on the fuse verification program was closed in Inspection Report (IR) 50-269,270,287/98-08. This LER is close Licensee actions in resolution of LER 50-287/97-01 were adequat.2 (Closed) VIO 50-269,270,287/97-14-02: Failure to Adequately Implement Lee Station Procedure (Closed) VIO 50-269270,287/97-14-03: Failure to Provide Lockout Reset Instructions (Closed) LER 50-269/97-06: Problems During Electrical Tests: Loss of Lee, Failure of Keowee 1, and Loss of Keowee 1 Auxiliaries
These items involved a series of events which occurred on June 20 and on June 23, 1997, affecting the Oconee standby electrical bus. The licensee stated in their December 17, 1997, reply to notices of violation that the failure to implement the Lee procedure was due to operator error. The reply also stated that the lockout reset instructions did not include a condition that resulted from equipment failures. The equipment failures were a relay timer and blown fuses. The LER described the series of events in detail and discussed corrective actions. The licensee has completed the corrective actions identified in the reply. These actions were also in the corrective actions discussed in the LER. These actions were changes to procedures, training of personnel, change out of equipment, error reduction techniques, and the installation of a modification. The inspectors verified the procedure changes, observed equipment change out (fuses), and observed the installation and testing of the modification to the field flashing breaker. The observations were documented in IR 50-269,270,287/97-1 Based on the corrective actions, the inspectors concluded that the licensee throughly addressed the causes of both violations. The corrective actions discussed in the LER were reasonable and were completed. Accordingly, the violations and the LER are close The inspectors concluded that the corrective actions were appropriate and the overall actions taken by the licensee were goo.3 (Closed) VIO 50-269,270,287/97-16-01: Failure to Implement Nuclear Systems Directive 408, Testing Related changes to PT/0/A/610/017, Operability Test of 4160v Breaker, revision 11 were verified by the inspectors. The changes were described in the licensee's response, dated February 25, 1998, to the violation. In addition, training was provided for operators to ensure that the engineered safeguards, breaker logic, and Keowee protection circuitry was understood by licensee personnel. Other corrective actions described in the licensee's response were also verified as complete. This violation is close The investigative report regarding the failure to perform an operability test of 4160.volt breaker was thorough and the corrective actions to prevent recurrence presented in the response letter were adequate. The immediate actions were timely and the long-term actions have been complete.4 (Closed) LER 50-269/97-001 (Revisions 0 and 1): TS Not Met Due To Deficient Procedures TS 3.1.2 limits the temperature of the coolant returning to the reactor vessel to greater or equal to 70 F (excluding instrument accuracy). The licensee identified that a potential existed for exceeding limits presented in TS 3.1.2. A PIP was prepared and the evaluation concluded that the limiting values had been met in the past, but no administrative controls were in place to prevent exceeding the TS limi Corrective actions presented in the LER were verified by the inspectors as complete The immediate corrective action was to raise the LPI cooler outlet temperature to 810 Fahrenheit (F) (70 F+1 1 F for inaccuracy). The inspectors confirmed that the current operating procedures reflect this same limit. A proposed revision to the TS has been prepared; therefore, this LER is close The licensee's corrective actions were complete and thoroug )
0 (Closed) URI 50-269,270,287/98-01-01:
Nuclear Safety Review Board (NSRB) Review of 10 CFR 50.59 Safety Evaluations This URI was opened pending: (1) resolution of the apparent differences between TS 6.13 and Nuclear System Directive (NSD) 309.10, Material Review, and (2) further review of how NSRB members review 10 CFR 50.59 safety evaluations. The licensee clarified NSD 309 to say that 10 CFR 50.59 safety evaluations, determined by the NSRB support staff to be not significant, would be reviewed by the NSRB Director or Alternate Director. The licensee also submitted Amendment 24 of the Nuclear Quality Assurance Program for approval. That amendment provided that at least one member of the NSRB would review each 10 CFR 50.59 safety evaluation. The inspectors confirmed that these changes aligned the NSD with TS 6.1.3 and the QA program. The inspectors also verified the method of using one member for review has been accepted by the NR The inspectors also reviewed the NSRB activities and found them to be consistent with these practices. The inspectors determined there was no violation of regulatory requirements involved. This URI is close I. Maintenance M1 Conduct of Maintenance M General Comments a. Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance activities:
WO 98058903-01 Inspection and Maintenance of KHU-2 PMG
WO 98084956-01 OE-12749, Leak Repair 2B OTSG Feedwater Risers
WO 98084956 Repair Feedwater Leaks on 2B steam generator
MP/0/A/1800/003A Retorquing-Body/Bonnet, Hinge Pin, Flange, Manway, and Miscellaneous Bolted Mechanical Connection Leaks, Revision 13
MP/0/A/1800/016 System Leakage Repairs Using Vendor Injection Methods, Revision 18
PT/0/A/0300/01 Control Rod Drive Trip Time Testing, Revision 13
OP/3/A/1 102/10 Controlling Procedure for Unit Shutdown, Enclosure 4.2, Performing Control Rod Drive Trip Time Test During Shutdown, Revision 155
WO 95013582-33 Cable Pull for Modification NSM 32885
IP/0/A/3010/06 Cable Pulling Procedure, Revision 13
PT/1 /A/0251/001 Low Pressure Service Water Pump Test, Revision 61
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- PT/O/A/0250/025 HPSW Pump and Fire Protection Flow Test, Revision 23 PT/3/A/025/024 HPI Full Flow Test, Revision 8 b. Observations and Findings 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 us Technicians were experienced and knowledgeable of their assigned tasks. The inspectors frequently observed supervisors and system engineers monitoring job progress. Quality control personnel were present when required by procedure. When applicable, appropriate radiation control measures were in plac Conclusion The inspectors concluded that the maintenance activities listed above were completed thoroughly and professionall M Leak Repair of Unit 2 Steam Generator Feedwater Risers a. Inspection Scope (62707, 92904)
On September 19, 1998, Unit 2 was shutdown to repair feedwater leaks on the 2B steam generator. The inspectors observed, reviewed, discussed with licensee personnel, and attended meetings concerning various phases of the activities associated with the feedwater leak repair on the 2A steam generato b. Observations and Findings Sine Unit 2 was restarted following its refueling outage in May 1998, the amount of leakage into the reactor building normal sump steadily increased to greater than gallons per minute (gpm). The licensee determined the leakage to be feedwater and decided to shut down the unit and address the leaks. On September 19, 1998, Unit 2 was shutdown and cooled to 260 degrees F. Licensee operations and maintenance personnel entered the reactor building and found leaks on the riser to shell flange of three feedwater risers on steam generator 2B and two feedwater risers on steam generator 2 Under Minor Modification ONOE-12749, the licensee removed the existing flange studs and replaced them with longer studs. Then a leak repair injection nozzle was installed on each stud and the combination was retorqued to the original torque value. The licensee then brought Unit 2 back to normal operating temperature and pressure and injected each nozzle with a thermal setting resin to seal the lea The inspectors observed portions of the injection nozzle installation and retorquin Licensee technicians had their procedures in the field with them and referred to the procedures often. Licensee quality control personnel were also present at the job sit The new studs were stamped with a material code and documentation was present in the work package to trace the studs back to a given heat number. Licensee technicians torqued the new studs and bolts to the torque value specified in the procedure, using the specified patter Conclusions The licensee carefully followed procedures and used good parts control during the seal injection of the Unit 2 steam generator feedwater riser M2 Maintenance and Material Condition of Facilities and Equipment M Fluid Leak Management (FLM) Program (Recovery Plan Item SE5)
a. Inspection Scope (62707)
The inspectors reviewed the licensee's FLM program that was implemented under the Oconee Recovery Pla b. Observations and Findings As part of the Recovery Plan, the licensee established the FLM program to identify, track, control, and mitigate fluid leaks. The program consisted of implementation of a leak management directive, procurement of suitable leak catch containers and accessories, and use of existing database tool The licensee issued procedure section Appendix I, Oconee Nuclear Station Specific Information, to NSD 104, Housekeeping, Material Condition, and Foreign Material Exclusion, Revision 14, as the leak management directive. This NSD appendix established a leak management coordinator and identified the process for the FLM program. As part of the process, Appendix I established an electronic log for tracking leaks. This log was to contain 13 specific pieces of information on each leak. When questioned by the inspectors, the licensee stated that the log was maintained as a leak management database. The inspectors found that one item specified in Appendix 1, fluid type, was not included in the database. Additionally, the inspectors observed several active leaks in the plant, but none of them were included in the database. The licensee stated they were in the process of further developing the database to correct these problems. Currently, the licensee uses its work management system to monitor active leaks and initiate work orders to repair the leaks. All active leaks observed by the inspectors were tracked by component number in the work management system. This matched the intent of the recovery plan. From randomly observed leak points in all three units, the inspectors found that the catch containers used to contain each of the observed leaks were installed and labeled properl Conclusions The database specified in the fluid leak management program directive was not yet fully developed. However, the fluid leak management program directive, catch containers, and database tools met the objective of the Recovery Plan. Recovery Plan Item SE5 is close M8 Miscellaneous Maintenance Issues (92902, 92700, 90712)
M (Closed) URI 50-269.287/98-06-13: Potential Steam Generator TS Issues (Closed) LER 50-269/98-08: Steam Generator Tube ECT Indications Not Repaired Due to Inadequate Guidance Results in Operation Prohibited by Technical Specifications (Closed) NOED 98-6-008: Notice of Enforcement Discretion for Duke Energy Corporation Regarding Oconee, Units 1 and 3 These open items referred to the problem of improperly analyzed tube end anomalies resulting in defective Steam Generator (SG) tubes being left in service. The licensee's review of past data showed that 319 tubes in SG 1A, 53 tubes in SG 1 B, 2 tubes in SG 3A and 59 tubes in SG 3B should have been plugged or repaired by re-rolling during the last refueling outage for Units 1 and 3. The inspectors agreed with the licensee's conclusions that the root causes appeared to be a combination of inadequate guidance for eddy current analysts and inadequate analysis of the eddy current dat The inadequate guidance involved the landmarks to be used for the outer limits of the pressure boundary. (The pressure boundary for this design steam generator is a 1-inch rolled area at the outer edge of the 24-inch thick tubesheet.) The inadequate guidance apparently caused some analysts to consider the boundary between the ferritic tubesheet and the austenitic cladding to be the limit of the pressure boundary instead of the outer limit of the austenitic cladding. Inadequate analysis was involved in cases where the reanalysis found indications in the ferritic region of the tubesheet, which is unquestionably a part of the pressure boundar Problems associated with the rolled pressure boundary of Babcock and Wilcox (B&W)
OTSGs are a relatively new phenomenon, and have only became a part of the normal steam generator tube inspection during the last outage for each unit. Units 1 and 3 had been inspected in this area for the first time during the last refueling outage. During the last Unit 2 refueling outage, a review of operating events at another facility caused Duke steam generator personnel to question their own procedures and thereby recognize the problem prior to putting Unit 2 OTSGs back into service. The Unit 2 steam generator tube end anomalies were repaired during the refueling outage which began in March 1998. The Unit 1 repairs were made during an outage in August 1998. The Unit 3 repairs will be made during the October 1998 outag The failure to include adequate guidance for eddy current analysts and the failure to correctly analyze eddy current data constitutes a violation. This non-repetitive, licensee identified and corrected violation is being treated as a Non-Cited Violation consistent with Section VII.B.1 of the NRC Enforcement policy and is identified as NCV 50-269,287/98 09-01, Steam Generators Returned to Service With Defective Tube M (Closed) VIO 50-269/97-16-06: Inadequate Control of Modifications This violation, issued January 24, 1998, contained three examples of modifications that were performed without following the modification process as described in NSD 30 The inspectors reviewed and verified completion of the corrective actions described in the licensee's response, dated February 25, 1998. All three examples were corrected and additional corrective actions were implemented to strengthen procedure adherenc The analysis and resolution concerning these examples of inadequate modifications control was timely and thoroug M (Closed) URI 50-269/98-02-06: Improperly Installed Valve Packing Gland Fasteners As reported in NRC IR 50-269,270,287/98-02, Valve 1HP-149, a one-inch vent valve on the reactor coolant pump seal water system, had one of two packing retaining nuts that did not have full thread engagement. Full thread engagement has been considered by the industry as a good maintenance practice, but this practice had not been included in maintenance procedure In this case, the licensee determined that there was 1/8-inch engagement on the nu An operability evaluation, documented in PIP 1-098-0944, concluded that 1-HP-149 was operable with one gland nut not fully engaged. The inspector reviewed the calculation and agreed that the valve was operable. To prevent recurrence, valve packing procedures MP/0/A1200/001, Revision 47, and MP/0/A/1200/001D, Revision 14 have been revised to require verification of full thread engagement. Based on the above, this URI is close Actions taken by the licensee regarding thread engagement were timely and complet M (Closed) LER 50-270/96-005-01: Potential Uncontrolled Release Via Main Steam Relief Valves due to Inadequate Work Practice
.This LER was previously reviewed in NRC IR 50-269,270,287/98-08, Section 08.4, as part of the closure for related violation EA 96-478-01014. The corrective actions presented in the LER were verified as complete at that time. Accordingly, this LER is close M (Closed) LER 0-269/98-01-00: Failure to Add New Keowee In-Service Test to Scheduling Process Results in Missed Surveillance (Closed) VIO 50-269,270,287/97-18-08: Failure to Establish And Implement Procedures-Three Examples (Note: This review applies only to example three; examples 1 and 2 are discussed in Section M8.6.)
The LER describes a situation where the surveillance interval for the two guide bearing oil system valves at Keowee was exceeded. The licensee declared both Keowee Units inoperable and proceeded to perform the required surveillance. The test was completed satisfactorily and operability was restored. The missed surveillance test was a new requirement that had not been added to the scheduling program. The corrective actions presented in the LER were verified as completed by the inspector Example three of violation 97-18-08 was issued covering this event. The licensee's April 5, 1998, response, which was accepted by the NRC on April 21, 1998, described the associated corrective actions. The corrective actions included issuance of a test procedure and a model work order, as well as other actions. These actions were verified complete by the inspectors; therefore, the LER and example three of the violation are close The licensee's analysis of this LER resulted in a self-initiated, broader review of problems with surveillance scheduling process. Resolution of the specific issue was timely and appropriat M (Closed) VIO 50-269,270,287/97-18-08: Failure to Establish and Implement Procedures-Three Examples (Note: This applies to examples one and two, example three is discussed above in Section M8.5.)
Regarding Example 1, the licensee's response, dated April 5, 1998, which was accepted by the NRC on April 21, 1998, described corrective actions for each exampl Completion of the corrective actions were verified by the inspectors. Replacement of the integrated control system was accomplished according to consistent rules which minimizes the problem as described in example one. Other corrective actions were verified by the inspector For Example 2, Procedure IP/0/A/2005/003, Westinghouse WTA Voltage Regulator Test, was revised. During calibration of the voltage regulator, the voltage adjuster cam switches are verified to be properly set. This violation is close The corrective actions taken by the licensee regarding failure to establish and implement procedures were timely and thoroug Ill. Engineering E2 Engineering Support of Facilities and Equipment E Repairs to Reactor Buildinq Protective Coatings (Recovery Plan Item NRC5)
a. Inspection Scope (37550)
The inspectors examined the protective coatings in the Unit 3 reactor building and reviewed the licensee's planned corrective actions to repair the coatings in areas where the coating had deteriorate b. Findings and Observations The licensee has initiated several PIPs to document and disposition deteriorated protective coatings in the Units 1, 2, and 3 reactor buildings. The inspectors accompanied licensee engineers and observed performance of a general visual walkdown inspection to examine the condition of the protective coatings inside the Unit 3 reactor building. The purpose of the walkdown inspection was to identify areas where coatings on the liner plate, concrete surfaces, or internal steel structures had deteriorated and prepare plans for removal and repair of the deteriorated coatings during the current Unit 3 refueling outage. Prior to the walkdown inspection, the inspectors attended a pre-job briefing during which the inspection plans were discussed in detail. Items discussed included safety, radiation protection practices, controlling procedures, visual inspection techniques, and documentation of inspection result The inspectors reviewed procedure MP/0/B/3005/013, Revision 0, Reactor Building Coating Inspection Procedure, and Surveillance Guide NCMM-1167.02, Revision 3, which provided the instructions for performance of the coating inspection. The procedures specified inspection prerequisites, acceptance criteria, inspection requirements, records, and qualifications of inspection personne The inspectors performed an independent inspection of the coatings to assess the adequacy of the licensee's walkdown inspection. During the walkdown, coatings were examined for any visible defects such as blistering, cracking, flaking/peeling, rusting, pitting, and physical damage. The following conditions were identified by licensee personnel and the inspectors:
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Coatings on portions of the dome and containment spray pipe support structure (lattice structure) were flaking/peelin Coatings on some miscellaneous structures such as ladders, handrails, pipe supports, etc. were peeling/flakin Coatings which had been repaired on portions of the liner plate and structural steel platform support steel were blisterin Minor corrosion was identified at some liner attachment Liner corrosion was identified in some areas which had not been previously repaired at the liner/concrete floor intersection at the expansion join Damaged coatings were identified in several high traffic areas. The damage to the coatings appeared to have been caused due.to maintenance activities (mechanical damage).
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Minor liner corrosion was identified in a few limited areas below the equipment hatch. Peeling/flaking coatings were also identified in a few areas on the liner plat Corrosion was identified at some platform structural steel connection The inspectors reviewed the following PIPs: 0-96-0146, 0-096-2414, 2-096-2657, and 3-096-2415. From review of the above PIPs, the inspectors noted that the licensee had previously identified similar discrepancies as noted above. The licensee's coating inspections were adequate to plan and prioritize the repair activities during the current Unit 3 refueling outage. The repairs to the coatings on the dome and containment spray piping support structure are planned for the next refueling outag Conclusions The licensee's walkdown inspections for coatings were adequate to plan and prioritize coating repair activities to be completed during the current Unit 3 refueling outage. The licensee's actions to address repairs to the coatings in the Unit 3 reactor building were performed in accordance with good engineering practices and NRC requirement E System Team DeveloDment (Recovery Plan Item SE4)
a. Inspection Scope (37550)
The inspectors reviewed the licensee's implementation of the System Team Development initiative to determine if it was consistent with the scope, schedule, and goals described in the Recovery Plan. This initiative was also reviewed for compliance with applicable licensee procedure b. Observations and Findings The System Team Development initiative was discussed in the Oconee Recovery Plan under the management focus area of System/Equipment Reliability. An Oconee Nuclear Station Directive 2.1.8, System Team Development, dated December 3, 1997, was established to define the scope, composition, and responsibilities of system teams. A quarterly meeting frequency was designated. A system team roster demonstrated that all system teams listed in the recovery plan were established and initial meetings were conducted. A self-assessment, dated June 19, 1998, stated that meeting attendance and scope at the second quarterly meetings were not consistent with the guidance specified in Directive 2.1.8. The self-assessment action plan included an action plan to improve meeting attendance and scop Conclusion The implementation of the system team development initiative was consistent with the scope, and schedule described in the Recovery Plan. The goals were not fully met ih that the licensee identified team member attendance and meeting scope as areas for improvement. However, appropriate self-assessment action was provided to monitor continuing performance related to this initiative which demonstrated the licensee was adequately addressing these deficiencies. No further inspection is required of this initiative. Recovery Plan Item SE4 is close E Management of Temporary Modifications (Recovery Plan Item SE6)
a. Inspection Scope (37550)
The inspectors reviewed the licensee's implementation of the Temporary Modification initiative. This initiative was reviewed to determined if actions met the scope, schedule and goals of the Recovery Plan. This initiative was also reviewed for compliance with applicable licensee procedure b. Observations and Findings The temporary modification initiative was discussed in the Oconee Recovery Plan under the management focus area of System/Equipment Reliability. The purpose of this initiative was to reduce the number of temporary modifications (TMs) installed in the plant, establish performance goals for Oconee Nuclear Station (ONS), and develop monitoring and tracking programs to evaluate plant performance against the goal Actions implemented by the licensee included establishing guidelines in May 1998 for the reduction of outstanding TMs and for the implementation of new TMs. The licensee had established performance goals and developed indicators to monitor plant progress prior to May 1998. Oconee Nuclear Site Directive 2.1.4, Control of Temporary Modifications, dated February 2, 1998, provided guidelines for the preparation, installation, control, and removal of TMs. Directive 2.1.4 specified that TMs not requiring a refueling outage for removal could be installed for up to 18 months. The guidance issued by the licensee in May 1998 stated that new TMs would be installed for no longer than 90 days. If a TM was going to be installed for greater than 90 days, then it should either be implemented as a minor modification or the TM was required to be approved by the Engineering Manager or the Station Manager. The inspectors noted that the new TM guidance had been incorporated into a proposed revision to ONS Site Directive 2. The inspectors reviewed various licensee performance indicators and noted that the number of TMs had been reduced from over 70 in January 1998 to 38 in September 199 Conclusions The inspectors concluded that implementation of the TM initiative was consistent with the scope, schedule, and goals described in the Oconee Recovery Plan. The actions taken by the licensee to reduce the number of old TMs and control the installation of new TMs were effective and contributed to the number of TMs being reduced from greater than 70 in January 1998 to 38 in September 1998. Recovery Plan Item SE6 is close E Secondary System/Component Reliability (Recovery Plan Item SE9)
a. Inspection Scope (37550)
The inspectors reviewed the licensee's implementation of the Secondary System/Component Reliability initiative to determine if it was consistent with the' scope, schedule, and goals described in the Recovery Plan. This initiative was also reviewed for compliance with applicable licensee procedure b. Observations and Findings The Secondary System/Component Reliability initiative was discussed in the Oconee Recovery Plan under the management focus area of System/Equipment Reliability. The purpose of this initiative was to analyze the reliability of the secondary systems and components based on past unit trips and power reductions. The initiative was to make recommendations (based on this analysis) to modify, repair, or perform preventive maintenance on those systems and components that had proven unreliable in order to increase overall site capacity factor and megawatt electric generate The secondary systems and components analysis was performed by ONS engineering personnel. Based on the analysis, engineering developed a critical equipment list and provided the list to the work control department in a memorandum dated August 18, 1998. The memorandum stated that the critical equipment list was a tool by which work control could determine those secondary systems and components which engineering had designated as critical to plant operation. Cancellation or delays in work on the designated equipment would require documentation of engineering's review to ensure that all risks were considered. The inspectors discussed the engineering memorandum and critical equipment list with work control personnel who indicated that the work control process was being reviewed in order to incorporate the engineering recommendations regarding documented engineering involvement in the preventive maintenance (PM)/corrective maintenance (CM) cancellations or delay The inspectors noted that, in addition to being on the critical equipment list, some of the systems and components were also on the licensee's operator work around (OWA) list and major equipment problem resolution (MEPR) top 15 list. Components on the OWA list and MEPR top 15 list received increased management attention during efforts to resolve the problem. Some of the components from the critical equipment list that were on either the OWA list or the MEPR top 15 list included the main turbine, once through steam generators, main feedwater pumps, and the electric generato The inspectors noted that other plant departments such as operations had reviewed the list and provided feedback to engineering with regard to adding other systems and components to the critical equipment list. Engineering personnel stated that an operations recommendation being added to the list was the raw cooling water syste This system was also being added to the MEPR top 15 lis Conclusions The inspectors concluded that implementation of the secondary system/component reliability initiative was consistent with the scope, schedule, and goals of the Oconee Recovery Plan. The actions taken by the licensee had resulted in increased engineering involvement and plant management attention to secondary system component problem Recommendations from an engineering analysis of selected systems and components were being incorporated into the licensee's work control process. Recovery Plan Item SE9 is close E Enhance Interface/Communication Between Engineering, Operations and Maintenance (Recovery Plan Item TD4)
a. Inspection Scope (37550)
The inspectors reviewed the licensee's implementation of the engineering interface item to determine if it was consistent with the scope, schedule, and goals described in the Oconee Recovery Pla b. Observations and Findings The inspectors reviewed meeting logs and verified that the routine meetings between engineering and operations were conducted as described in the recovery plan. A major focus of these meetings was the reduction of OWAs. A success indicator was that there were eighteen OWAs resolved in 1998 compared to six in 1997. A plant concern and action register was established for operations to focus accountability for short-term issues affecting the plant. Meeting minutes from the engineering-maintenance routine meetings demonstrated this aspect of the recovery plan item goals. An action item tracking tool was established for maintenance to identify short-term high priority items for increased focu Conclusion The implementation of the engineering-operations-maintenance interface item was consistent with the scope, schedule, and goals described in the Oconee Recovery Pla Initial results indicated that the engineering interface with the plant was improve Recovery Plan Item TD4 is close E Post-Modification/Maintenance Testing (PMT) Process (Recovery Plan Item TD6)
a. Inspection Scope (37550)
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 and long term corrective actions developed by a PMT improvement team that was established in April, 1997. The improvement team report was documented in PIP 0-097-1691, dated, June 3, 199 Although a goal of the team was a comprehensive identification and categorization of PMT program problems, the report did not clearly identify what the PMT problems were, as defined by historic findings associated with the PMT program. Other team goals included a PMT process flow chart and establishment of ownership of the PMT program. The developed flow
chart did not fully encompass the PMT process and no program ownership was established. The root cause stated that the PMT process was a fragmented program without sufficient technical support and management oversight to assure the program serves its intended function. The 37 corrective actions did not address increased technical support or management oversight. The one exception was a long term corrective action for engineering to develop a comprehensive PMT data base for plant equipmen In general, the PMT enhancement effort did not appear well focused in that a direct link was not established between program problems, causes, and corrective actions. The apparent method to develop corrective actions yielded several potential program improvements. A strong point was the clarification and designation of PMT program roles and responsibilities for the various groups, i.e. engineering, operations, work planning, and maintenanc The recovery plan status for this item stated that the short-term PMT recommendations were implemented by September 18, 1997, although several recommendations/
corrective actions were not implemented. These included establishing of a dedicated PMT scheduler individual, developing and documenting a control process for work orders in the work control center, and establishing of a generic procedure for B31.1 and non-inservice tests and inspection Several of the long-term corrective actions have not been achieved although the due date in the PIP had passed. These included developing a template for the amount of detail required for PMT plans, revising Work Planning Manual (WPM) 501, Post Maintenance Testing, revision 1, to delete invalid references, developing and documenting in WPM-501 the philosophy on use of component identification versus work items on work orders, and developing and documenting in WPM-501 the minimum information requirement to make initial schedule ties for PMT activitie It was evident that the licensee extended a sincere effort to improve the PMT progra This effort was initiated prior to the recovery plan development and then was later incorporated into the plan. Discussion with the PMT team indicated that the evolution of several team recommendations were not documented although the PMT performances for the subsequent Unit 1 refueling and steam generator forced outages were closely monitored for success of the short term actions. The report did not clearly indicate how many PMT problems occurred each outage, the responsible organization, or deficient program area, therefore it was difficult to determine the effectiveness of the progra The PMT implementation provided strong outage support in the previous outages by reviewing test activities prior to the outage and reviewing schedule logic ties for inservice testing. The implementation team identified a near miss on the steam generator forced outage which indicated that the station was still susceptible to PMT problems. The implementation team pre-outage review was a temporary measur A continuing improvement team which was planned by the original team was recently established to evaluate the effectiveness of the recommendations implemented. The charter for this team included the identification of indicators to assess PMT performanc Conclusion The licensee's implementation of the PMT improvement initiative did not appear well focused. The trends and areas of deficient performance were not clearly defined and corrective actions did not clearly address the stated root causes. A temporary measure outage related PMT problems which precluded PMT deficiencies during those outage The implementation was consistent with the scope described in the recovery plan; however, the schedule and goals were not yet consistent. It was not evident that the PMT program improvements have yet assured that all PMTs are correctly designated, scheduled, and executed, which was the stated goal for this recovery plan ite Recovery Plan Item TD6 remains open pending further inspectio E7 Quality Assurance in Engineering Activities E Operating Experience Feedback (Included Under Recovery Plan Item NRC2)
a. Inspection Scope (37551)
The inspectors reviewed the operating experience feedback (OEF) program as part of Oconee Recovery Plan Item NRC2, Safety Assurance Quality Verificatio b. Observations and Findings Recovery Plan Item NRC2 encompasses the licensee's controls in identifying, resolving, and preventing problems. Included as part of these controls, the OEF process was determined by the licensee to not be up to their expectation The OEF improvement goal was met by the noticeable changes discussed below:
The site personnel working with PIPs, modifications, procedures, and radiological/chemical practices are expected to utilize OEF when necessary. The use of the OEF program is monitored by the onsite safety assurance grou *
The onsite safety assurance group heads up the centralized screening team that reviews the PIP forms, on a daily work day basis, for OEF verification purpose The team, in addition to the safety assurance group member, had representatives from operations, maintenance, and engineerin *
OEF items are discussed at the morning site management meetings. This includes other Duke Power sites, INPO information, and NRC items. Ownership of various OEF items are also discusse The inspectors found that operating experience feedback is available onsite to engineering, operations, and maintenance personnel. The OEF is required to be used for all PIPs of Category 1 or 2 and by all failure investigation process teams. The inspectors have observed that OEF has been used on numerous PIPs reviewed in the last several months. The OEF portion of Recovery Plan NRC2 is close Conclusions The inspectors concluded that an operating experience feedback process is in effect, is used by applicable personnel, and is considered goo E Safety System Engineering Audit (SSEA) of Emergency Feedwater (EFW) (Rcovery Plan Item DB9)
a. Inspection Scope (37550, 40500)
In IR 50-269,270,287/98-08, the inspectors had reviewed the licensee's SSEA of EFW to assess the scope and findings. The inspectors had not completed that assessment pending the resolution of the significance of inspector-identified potential design issue During this inspection, some additional information was obtained relating to the assessment of the licensee's SSEA of EF b. Observations and Findings The inspectors found that four deficiencies related to EFW that were identified by the NRC were not identified by the licensee's SSEA. Those four items were:
The UFSAR stated that the EFW system can withstand a single failure concurrent with a secondary pipe break and a loss of offsite power and still perform its safety function. That statement was not consistent with the 1973 high energy line break report which stated that a main feedwater line break in the turbine building can cause failure of the EFW syste An NRC and licensee walkdown confirmed that a main feedwater line break or an auxiliary steam line break could cause a loss of all three trains of 4160 volt alternating current (AC) safety-related power and a 250 V direct current (DC)
switchgear and consequently result in a failure of the EFW syste The licensee's PIP 0-098-4208, which the licensee opened in response to this inspector concern, concluded that the UFSAR needed to be change The UFSAR stated that the EFW system can withstand a single failure concurrent with a secondary pipe break and a loss of offsite power and still perform its safety function. That statement was not consistent with the probabilistic risk assessment (PRA), which stated that a failure of valve C-1 87 (which dumps the upper surge tank water to the condenser hotwell) concurrent with a main feedwater lin6 break can cause a failure of the EFW system. The EFW failure would result from the fact that all EFW pumps take a suction on the upper surge tan The licensee's PIP 0-098-4208, which also addressed this inspector concern, concluded that the UFSAR needed to be change Since 1986, the EFW design has relied on operation of the EFW pumps at runout, with insufficient NPSH, for about two minutes. However, at the time of the EFW SSEA in 1998, the licensee had no design record assuring that the EFW pumps could operate at runout without suffering immediate damage. There were no letters from the pump vendor certifying the ability of the installed EFW pumps to operate at runout. Also, there were no records of tests or analyses to verify that the pumps could operate at runou The EFW SSEA did not identify that there were no design records to document the ability of the EFW pumps to operate for over two minutes at runout. The lack of design records is discussed further as a violation of NRC requirements in Section E The UFSAR stated that, once started, the EFW pumps will continue to run until manually stopped by the operators. This statement was incorrect in that it overlooked the automatic trip of the turbine-driven EFW pump at a low OTSG pressure of 500 pounds per square inch gauge (psig).
Section E8.2 of this inspection report describes three potentially significant design vulnerabilities with the licensee's EFW system that were identified by NRC inspectors and were not identified by the licensee's SSEA, that will be the subject of further
inspector followup. Section E8.4 of this report discussed an URI opened to track these UFSAR discrepancies The licensee noted during discussion with the inspectors that by design, the'licensee's EFW SSEA effort was significantly less than for the high pressure injection (HPI) and low pressure injection (LPI) SITA. The EFW SSEA involved 26 man-weeks of effort, which was about half of the 50 man-weeks of effort involved in the HPI/LPI SIT Conclusions The inspectors concluded that the licensee's SSEA of EFW was weak in that it did not identify three potentially significant design vulnerabilities, one violation, and some inaccurate UFSAR statements that were identified by the NR E8 Miscellaneous Engineering Issues (92903)
E (Closed) IFI 50-269.270.287/97-18-09: Review of the Root Cause Analysis for Agastat Time Delay and Type D87 Timer Relays This item was opened due to failures in the electrical control systems of the Keowee Hydro-electric Plant (KHP) on two occasions. On January 9, 1998, KHP Unit 2 failed to complete a normal start, and on January 14, 1998, the unit failed to return to the preset automatic voltage level during a surveillance tes The failure to complete the normal start was due to an open coil on an Agastat type E7012 relay. The opened coil prevented the voltage regulator from going into the automatic mode of operation. This in turn prevented the completion of a normal star The root cause analysis determined that this was a random failure and was based on tests performed on the failed coil, no previous coil failures, and correct relay coil applicatio The failure to return to the preset automatic voltage level was due to a failed Cutler Hammer type D87 timer relay. The root cause analysis determined that the failure was an industry recognized failure involving new equipment, infant mortality. To arrive at this conclusion, the licensee performed extensive testing on the relay The inspectors concluded that the root cause analyses for both relays was excellent in that they were very through, comprehensive, technically sound, and identified the most probable cause of the failures. This item is close E (Open) Inspector Followup Item (FI) 50-269,270,287/98-08-05: EFW Potential Design Basis Issues a. Inspection Scope (92903, 37550)
This IFI was opened for further NRC review of the following EFW potential design vulnerabilities: (1) a single active failure in the open position of valve C-1 87 coincident with a main feedwater line break causing a loss of EFW; (2) a main feedwater line break in the turbine building causing consequential failures of the EFW system and all three trains of safety-related 4160v electrical switchgear; (3) the reliance on operator action to throttle EFW flow within three minutes while using nonsafety-related equipment and while the EFW pumps operate with insufficient NPSH; and (4) poor operator access to the handwheel of Unit 3 EFW flow control valve FDW-316. The inspectors conducted further followup on these issue b. Observations and Findinqs During this inspection, the licensee completed a licensing basis review of the first two potential design vulnerabilities listed above. The inspectors noted that, in that review, the licensee stated that the impact on surrounding equipment of a main feedwater or other high energy line break, resulting in a loss of EFW, was not considered in the 1981 1982 NRC review and approval of the modified EFW system as a safety-related syste The licensee also stated that the failure of valve C-187, resulting in a failure of the EFW system, was not considered during the 1981 - 1982 NRC review and approval of the EFW system. The licensee's conclusion was that the UFSAR statement, that the EFW system could withstand a single failure concurrent with a secondary pipe break and a loss of offsite power, was incorrect. The licensee further concluded that an UFSAR revision was needed to clarify the design basis of the EFW system. The licensee did not make any conclusions about potential related nonconforming conditions or unreviewed safety questions. The inspectors noted that the licensee would have to address those considerations in the 50.59 safety evaluation for the UFSAR revision. The inspectors plan to review the licensee's 50.59 safety evaluation when it is complete Also during this inspection, related to the third potential design vulnerability listed above, the inspectors reviewed the licensee's letters from the EFW pump vendor dated August 13 and August 28, 1998. In those letters, the pump vendor stated that there should not be a catastrophic failure of the EFW pumps if they operate at a runout condition for less than five minutes. PIP 0-098-4124 addressed the lack of automatic runout protection for the EFW pumps, and in it the licensee relied on the letters from the pump vendor for evidence that the EFW pumps would operate for up to five minutes in a runout conditio An operability evaluation for that PIP concluded on September 2, 1998, that the EFW system was operable. However, the inspectors noted that the letters from the vendor addressed only the motor-driven EFW pumps, while the PIP and operability determination relied on the letters from the pump vendor for operability of the motor driven and turbine-driven pumps. The inspectors noted that, since the turbine-driven pumps were substantially different than the motor-driven pumps (i.e., they have about twice the capacity), the basis behind the vendor letters may not apply to the turbine driven EFW pumps. The licensee stated that they would look into their basis for determining that the turbine-driven EFW pumps were operabl The inspectors also noted that the licensee had effectively changed the design criteria for the EFW pumps in 1986 when they recognized that the EFW system operability would rely on the pumps' ability to run for a few minutes at a runout condition without suffering damage. The reliance on the EFW pumps operating at runout was documented in Oconee Design Nonconformance Report DNC-0064, dated August 4, 1986; in Oconee Incident Investigation Report No. 86-25-04, dated September 24, 1986; and in LER 50-269/86-10, Potential for Loss of Emergency Feedwater Due to Pump Runout for Certain Transients, dated September 29, 1986. The inspectors noted that the 1998 letters from the pump vendor did not describe any analyses or tests to support the statement that there should not be a catastrophic failure of the EFW pumps if they operate at a runout condition for less than five minutes. Further, the licensee had no records of such analyses or test CFR 50, Appendix B, Criterion Ill, Design Control, requires that measures be established for the review for suitability of application of equipment that is essential to the safety-related functions of the systems and components. Criterion Ill further requires that design control measures shall provide for the verifying or checking the adequacy of design, such as by a suitable testing program. Where a test program is used to verify a specific design feature, it shall include suitable qualifications testing of a prototype unit under the most adverse design conditions. 10 CFR 50, Appendix B, Criterion XVII,
SQuality Assurance Records, requires that sufficient records shall be maintained to furnish evidence of activities affecting quality. The inspectors identified the licensee's lack of quality assurance (QA) records of analyses or tests to assure and verify the ability of the EFW pumps to operate at runout conditions, as relied upon to mitigate a design basis accident since 1986, as a violation of Criteria Ill and XVII. This issue is identified as VIO 50-269,270,287/98-09-02: No QA Records to Assure the Ability of EFW Pumps to Operate at Runou The inspectors noted that the licensee had recently missed two opportunities to identify this violation. One missed opportunity was the operability evaluation for PIP 0-098 4124, dated September 2, 1998, that evaluated the reliance on EFW pumps operating at runout for about two minutes and the reliance on operator actions to throttle EFW within three minutes. Licensee management had discussed this operability evaluation with NRC management. The second missed opportunity was the licensee's SSEA of EFW, which is discussed in Section E Conclusions The inspectors identified a violation of 10 CFR 50, Appendix B, Criterion Ill, Design Control and Criterion XVII, Quality Assurance Records, in that there were no QA records of tests or analyses to assure the ability of the EFW pumps to operate at runout as relied upon to mitigate a DBA since 1986. Also, the licensee had missed two recent opportunities to identify this violatio In addition to the four potential design vulnerabilities listed in the Inspection Scope above, this IFI remains open for inspector followup of: 5) the licensee's basis for determining that the turbine-driven EFW pumps were operable on September 2, 199 E (Closed) VIO 50-269,270287/98-03-07: Incorrect and Non-conservative Assumptions In Control Room Operator Dose Calculations a. Inspection Scope (92903, 37550)
The inspectors reviewed the licensee's response to this violation and followed up on the stated corrective action b. Observations and Findings The inspectors had previously verified the licensee's changes to the emergency operating procedures (EOPs) to direct operators to start the CRVS booster fans within 30 minutes and documented that in IR 50-269,270,287/98-03. The inspectors had also observed the improved sealing of the control room ventilation system (CRVS) ducting and part of the licensee's tracer gas testing of the control room envelopes and documented that in IR 50-269,270,287/98-08. During this inspection, the inspectors reviewed the licensee's final report on the tracer gas tests. The inspectors considered that the test methodology, data collection, and data analysis were appropriate. The test results verified that the licensee's efforts in sealing the CRVS ventilation ducts and the control room envelope were effective in reducing the unfiltered air in leakage. The inspectors verified that the measured unfiltered air in leakage was substantially less than the 300 cubic feet per minute assumed in the licensee's current operator dose calculation The inspectors reviewed licensee records of training of engineering personnel on this event. The licensee had not yet updated the operator dose calculations to reflect the results of the tracer gas tests and also had not yet updated the UFSAR as appropriate,
but these action items were being tracked in a PI The inspectors noted that the CRVS and control room habitability were currently operable, but nonconforming. However, the licensee had efforts in process to resolve that condition. The inspectors will followup on the resolution of the nonconforming condition as part of existing Unresolved Item (URI) 50-269,270,287/98-03-08, Licensing Basis Issues With Control Room Habitabilit Conclusions The inspectors concluded that the tracer gas tests of the CRVS represented a substantial improvement in the licensee's ability to assure operability. Violation 50 269,270,287/98-03-07 is close E Updated Final Safety Analysis Report (UFSAR) Review Project (Oconee Recovery Plan Item DB5)
a. Inspection Scope (37550, 40500)
In IR 50-269,270,287/98-08, the inspectors had identified and documented some incorrect statements in the UFSAR that the licensee's UFSAR Review Project had not identified. During this current inspection, the inspectors further reviewed and assessed the licensee's UFSAR Review Projec *
b. Observations and Findings This item was included in the Oconee Recovery Plan under the Management Focus Area of Design Basis. During this current inspection, the inspectors further reviewed UFSAR Chapter 10 on the EFW system and identified additional UFSAR statements that appeared to be incorrect or incomplete and had not been so identified by the licensee's UFSAR Review Project. The inspectors reviewed approximately ten such UFSAR statements with licensee engineering personnel. The most significant was the statement that the Oconee EFW system was able to "perform its safety-related function in the event of a single failure coincident with a secondary pipe break and the loss of station auxiliary AC power." The inspectors had identified plant design conflicts with this statement, as discussed in Sections E7.2 and E8.2 of this IR. Licensee engineering personnel initially disagreed with this inspectors' finding on the basis that the UFSAR Review Project had identified this discrepancy. Subsequently, licensee engineering personnel gave the inspectors a 17-page document they had prepared to substantiate that the UFSAR statement was correct. However, after further review and consideration, licensee engineering personnel agreed that the UFSAR statement was inaccurate and that the UFSAR project had not identified the inaccuracy. They also agreed with the other inspector-identified UFSAR inaccuracies. Licensee management stated that they would revise the UFSAR review project to enable it to identify such types of UFSAR inaccuracies and then review all UFSAR chapters agai The inaccurate statement, that the EFW system was able to "perform its safety-related function in the event of a single failure coincident with a secondary pipe break and the loss of station auxiliary AC power," had been made by the licensee to the NRC in 1979 correspondence related to the post-TMI action item to improve the design of the EFW system. The inspectors plan to followup on whether the NRC relied upon this inaccurate information in approving the licensee's EFW system design. The inspectors also plan to follow up on the other inaccurate UFSAR statements as described in Section E7.2 and E8.2. The issue of inaccurate EFW system information in the UFSAR will be tracked as URI 50-269,270,287/98-09-03: Inaccurate Emergency Feedwater System Information in the UFSA Conclusions The inspectors concluded that the UFSAR Review Project failed to identify several inaccurate statements in the UFSAR. An URI concerning inaccurate EFW system information in the UFSAR was opened to followup on whether the NRC relied upon this information in approving the licensee's EFW system desig E Generic Letter 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions. dated September 30. 1996 (Oconee Recovery Plan Item D138)
a. Inspection Scope (37550)
The inspectors reviewed the licensee's implementation of this Recovery Plan item associated with the resolution of Generic Letter (GL) 96-06 issues to determine if the implementation was consistent with the scope, schedule, and goals described in the pla b. Observations and Findings The status of the licensee's GL 96-06 actions was consistent with the schedule provided to the NRC in the GL 96-06 response. The Unit 3 operability review was completed and the reactor building auxiliary cooling units (RBACUs) returned to service. The operability review and RBACU return to service were discussed in IR 50-269,270,287/98-08. The scheduled date for the Unit 1 and 2 operability evaluation completion was extended to February and March 1999, respectively, due to the requirement for independent analysis rather than a similarity analysis to Unit 3 as originally planned. This issue is being tracked via LER 50-269/97-02 and the licensee's continuing supplemental responses to GL 96-06. The long-term resolution to resolving the piping code compliance issues for the low pressure service water piping (LPSW) for the reactor building cooling systems was being pursued in conjunction with an industry effort to resolve GL 96-06 issues. The Electric Power Research Institute (EPRI)/Nuclear Energy Institute (NEI) led effort is anticipated to be resolved in the summer of 1999. The licensee's actions to address the operable but non-conforming condition associated with the LPSW piping were consistent with the requirements of Generic Letter 91-18, Information to Licensees Regarding'NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions, Revision 1. A 50.59 safety evaluation was performed for the non-conforming condition and a schedule was established for resolution of the condition. The timeliness of the remaining corrective actions was dependent on the EPRI/NEI study previously discusse Conclusion The licensee's actions on the GL 96-06 Recovery Plan Item DB8 were consistent with the scope, goals, and schedule described in the plan. Outstanding actions are appropriately tracked via LER 50-269/97-02 and supplemental responses to GL 96-0 This item is close E (Closed) VIO 50-269287/97-14-06: Failure to Take Emergency Feedwater (EFW)
Recirculation Valve Corrective Action The inspectors reviewed and verified the corrective actions described in the licensee's response letter, dated December 17, 1997, and accepted by the NRC on January 8,
199 This violation involved failures of the automatic recirculation valves on the motor driven EFW system. These valves were installed in 1994 and had no operational problems until 1997 when three failures occurred. The corrective actions were not adequate to prevent similar failures as of October 199 The licensee 's response to this violation provided corrective actions to correct the problem and included installation of strainers on the hot well suction path. These corrective actions were verified as completed by the inspectors. The hot well was the most likely origin of the foreign material, therefore it was decided that strainers in this location would do the most good. The other corrective actions would also contribute to improving the reliability of the system. This violation is close The analysis and resolution of a problem with the emergency feedwater recirculation valve was through and satisfactor E (Closed) VIO 50-269/97-14-08: Inadequate Engineering Evaluation for Lifts Over Safety-Related Components The licensee's response, dated December 17, 1997, was reviewed and verified by the inspectors. The response, accepted by the NRC on January 8, 1998, indidated a procedure would be developed to address handling heavy loads with mobile crane The procedure, MP/0/B/17810/055, Rev. 0, Operation of Mobile Cranes Over/Around Safety Related Structures, Systems, or Components, was issued and verified by the licensee on August 26, 1998. The required 1OCFR50.59 evaluation for the procedure was reviewed by the inspectors. No questions were identified with the evaluation. This
violation is close The analysis and resolution for this violation was complete and timel E (Closed) VIO 50-269270287/97-16-08: Failure to Conduct Required Review of Test Results The corrective actions described in the licensee's response, dated February 25, 1998, and accepted by the NRC on March 10, 1998, were verified as completed. The corrective actions were completed on February 12, 1998. Site Directive 2.4.1 was revised to require as-found data to be collected when making set point changes, which are controlled by engineering documents. This violation is close Once the issue of not reviewing test results was identified, the licensee promptly performed an investigative report. The analysis and resolution were complete and timel E (Closed) VIO 50-270,287/97-15-09: Failure to Update the UFSAR Regarding Fuel Enrichment This violation involved a statement in Section 4.3.3.1.4, Fuel Misloading, of the UFSAR that was not updated in a timely manner. This section stated that fuel misloading is prevented by the use of one fuel enrichment per assembly. However, the current fuel design employs the use of axial blanket fuel rods which have upper and lower regions of reduced enrichment within a single fuel rod. The use of axial blanket fuel rods was approved in 1994. Appropriate reviews and approvals were obtained at that time, but Section 4.3.3.1.4 of the UFSAR was not update The corrective actions presented in the licensee's response, dated January 15, 1998, were verified as completed by the inspectors. Section 4.3.3.1.4 of the UFSAR has been
.28 updated and the other actions to prevent a recurrence have been implemented. This violation is close The licensee's analysis and resolution for failure to update the UFSAR was through and timel E8.10 (Closed) VIO EA 97-298 - 06014: Failure to Assure Design Configuration Control was Maintained for Letdown Storage Tank (LDST) Level Instrumentation Valves The licensee's response, dated November 5, 1997, which was accepted by the NRC November 21, 1997, was reviewed and the corrective action plans were verified by the inspectors. The planned completion date for this commitment was extended to March 1, 1999, by letter dated, August 31, 199 The violation involved the configuration status of instrument root valves for the LDS Some of the subject valves were not labeled and their status was not known. The licensee conducted a review for all three units and noted several discrepancies. These have been corrected. The root valve verification program was expanded to include critical root valves outside containment and where valve position was not self-revealin To date about 10000 valves have been verified as correct or errors were logged for correction. There are about 2000 more valves yet to verify and to complete the equipment database. This activity has been scheduled and is in progress. This violation is close The licensee's analysis and resolution concerning a failure to assure that the design basis for valves in the Unit 1, 2, and 3 letdown storage tank instrument lines were correctly translated into station procedures, was timely and complet E8.11 (Closed) IFI 50-269,270,287/96-03-04: Installation of New Ground Detection Equipment One of the recommendations in a design study, titled "125 VDC Vital Instrumentation and Control System Ground Detection, Location, and System Operation," regarding ground issues at Oconee, dated February 1, 1995, was to install ground detection equipment with greater sensitivity than originally installed. New ground detection equipment has been purchased and is scheduled for installation by NSM 3004. Installation has been scheduled for completion by the middle of 1999. Other recommendations of the design study have been complete The new system will enhance the ability to detect grounds. The ground detection currently in use is considered adequate as discussed in NRC Inspection Report 50 269,270,287/96-03, Section 4.7.2. This IFI is close The licensee initiated a design study report and a PIP to resolve ground issues. The related study was thorough and made several recommendations which were adopte E8.12 (Closed) VIO 50-269.270,287/98-02-12: Failure to Adequately Review Calculations in the Core Operating Limits Report (COLR)
This violation involved an existing error in the application of the energy deposition factor (EDF) when determining the operational power-imbalance limits. The kilowatt per foot limits were already incorporated in the EDF, which was different than the vendor's past practice for providing these limits. This resulted in double counting for the EDF, which resulted in slightly non-conservative operational power-imbalance limits at the middle of the cycle. The primary root cause was determined to be poor communication between
the fuel vendor and the license The corrective actions described in the licensee's response, dated May 20, 1998, and accepted by the NRC on May 29, 1998, were verified as completed by the inspector As part of the corrective actions, an assessment of the reload design process was conducted. A team of licensee personnel visited the vendor's facilities to conduct the assessment. In particular, the interfaces and communications between the vendor and the licensee was examined and improved. This violation is close The licensee's engineering, analysis, and resolution of an error in the energy deposition factor for determining operational imbalance limits was thorough and well don IV. Plant Support Areas S2 Status of Security Facilities and Equipment a. Inspection Scope (81700)
The inspectors evaluated the status of security facilities and equipment to determine whether they met the licensee's commitments in the Duke Power Nuclear Security and Contingency Plan (PSP), applicable security procedures, and NRC regulatory requirements. Areas evaluated were personnel search equipment and vehicle barrier system (VBS).
. Observations and Findinqs Personnel Search Equipment The inspectors verified that personnel, hand-carried packages or material, and delivered packages or materials were searched according to Sections 5, 7, and 9 of the PSP. The inspectors also observed the search equipment tested according to Security Procedures (SP) 403, 404, and 405. The inspectors reviewed records that documented the operational and performance weekly and quarterly testing of the metal detectors, explosive detectors, and the X-ray equipment. These searches were either by physical search or by search equipment. The inspectors observed security personnel search personnel using metal and explosive detectors for firearms, explosives, incendiary devices, and other items that could be used for radiological sabotage. Hand-carried packages or materials were searched by X-ray devices or manually searched by security personne Vehicle Barrier System The inspectors reviewed Appendix 2 of the PSP and SP 622 to ensure that licensee's VBS commitments were according to 10 CFR 73.55(c)(7). The inspectors verified by touring the site perimeter that the VBS was in place and functioning according to the PSP and SP. The licensee continued to use a combination of anchored jersey barriers, cables, and bollards. The licensee used both active and passive barriers. The inspectors reviewed quarterly and annual inspection records of the VBS and found that the license was complying with the PSP and SP testing and maintenance commitment Conclusions The licensee's security facilities and equipment were determined to be reliable and effectively maintained. The good maintenance support was the major factor to continued operability of the personnel search equipment and vehicle barrier syste *
S4 Security and Safeguards Staff Knowledge and Performance a. Inspection Scope (81700)
The inspectors evaluated the security organization's response capability to security threats, contingencies, and routine response situations, to ensure consistency with the SPs and PS b. Observations and Findings Security Force Requisite Knowledge The inspectors randomly reviewed 21 security personnel including supervisors, and witnessed approximately 10 others in the performance of their duties during normal operations. Members of the security force were knowledgeable in their duties and responsibilities, response commitments and procedures, and armed response tactic The inspectors found that armed response personnel had been instructed in the use of deadly force as required by 10 CFR Part 7 Response Capabilities The inspectors reviewed randomly selected response drills and exercise critique sheets conducted since the beginning of January 1997. The licensee had documented procedure drills, response drills, tabletop exercises, switchboard drills, and site emergency exercises. Most records had documented the drills' objectives, weaknesses and strengths. Documented critique sheets indicated that the shifts were not balanced in the number and frequency of drills and exercises conducted. The inspectors discussed this issue with the security training personnel and security management. The licensee indicated that this had been identified and closer monitoring was in effect and data base tracking had been initiated to resolve this issu Conclusion The security force personnel possessed appropriate knowledge to carry out their assigned duties and responsibilities, including response procedures, use of deadly force, and armed response tactic S6 Security Organization and Administration a. Inspection Scope (81700)
The inspectors interviewed management personnel and reviewed licensee documentation to determine the level of management support for the licensee's physical security progra b. Observations and Findings The inspectors interviewed management and non-management personnel and reviewed security related documents to determine the breadth and depth of the support provided and program effectiveness resulting from that support. The interviews indicated that the range of support provided by management was from good to excellent, depending on the individual interviewed. Licensee management exhibited an awareness and favorable strong support system for the security program:
-
There had been an increase in security personnel since the beginning of 199 The long-term total down trending of hardware and human error event The decrease in closed circuit television environs and failure events, perimeter intrusion detection system (PIDS) failures, vital doors' failures, search equipment failure The continued implementation of the vehicle barrier syste The security management's support of security personnel innovative and progressive approaches to enhance current policies and procedures and resolve developing issues before the issue becomes a problem. This was demonstrated in the excellent tracking and trending program administered by the security personne The following areas indicated a need for continued management review to improve their status conditions:
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An increase in PIDS nonenviron hardware false alarm An increase in human errors in unsecured vital door events during outage An increase in control of security access badge event Conclusion Site. and security management provided good support to the Physical Security Progra S7 Quality Assurance in Security and Safeguards Activities a. Inspection Scope (81700)
The inspectors evaluated the audit and self-assessment program and procedures, based on commitments in Sections 11 and 16 of the PSP and NSD No. 208. This review also ensured compliance with the requirement for an annual audit of the security and contingency programs. Also, the qualifications and independence of the audit program auditors were evaluate b. Observations and Findings The audit program required an audits of the security program, and the Security and Contingency Plan at least every twelve months. Persons conducting the audit were independent of both site security management and security supervision. The audit included a review of routine and contingency security procedures and practices. The regulatory audit group performed Departmental Audit SA-98-32(ALL)(RA) Fitness for Duty and Station Security on January 19-February 6, 1998. Three recommendations, two strengths, and six findings were identified. The recommendations and findings were not regulatory issues. The audit report concluded that overall, the security program at the Oconee Nuclear Site was effectively implemente Conclusion The last safeguards audit was thorough, complete, and effective in uncovering weaknesses in the security system, procedures, and practices. The audit report concluded that the security program was effectively implemented, and recommended appropriate action to improve the effectiveness of the security progra S8 Miscellaneous Security And Safeguards Issue (92904)
S (Closed) VIO 50-269. 270, 287/98-004-01: Safeguards Information Container Found Unsecured and Unattended The licensee investigated, documented and implemented corrective actions as described in PIP 4-098-1025. The responsive and corrective actions of the security and engineering organization to prevent recurrence of this type of violation were adequat 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 October 21, 1998. The licensee acknowledged the findings presented. No proprietary information was identified to the inspector Partial List of Persons Contacted Licensee L. Azzerello, Mechanical System/equipment Engineering Manager E. Burchfield, Regulatory Compliance Manager T. Coutu, Scheduling Manager T. Curtis, Superintendent of Operations 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. Melin, Superintendent of Maintenance M. Nazar, Manager of Engineering M. Salim, Coatings Engineer J. Smith, Regulatory Compliance J. Twiggs, Manager, Radiation Protection L. Waggoner, Corporate Coatings Specialist Other licensee employees contacted during the inspection included technicians, maintenance personnel, and administrative personne NRC D. LaBarge, Project Manager
Inspection Procedures IP37551 Onsite Engineering IP37550 Engineering IP40500 Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP61726 Surveillance Observations IP62707 Maintenance Observations IP71707 Plant Operations IP71750 Plant Support Activities IP81700 Physical Security Program IP90712 In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP92700 Onsite Followup of Written Event Reports IP92901 Followup - Plant Operations IP92902 Followup - Maintenance IP92903 Followup - Engineering IP92904 Followup-Plant Support IP93702 Prompt Onsite Response to Events Items Opened, Closed, and Discussed Opened 50-269,287/98-09-01 NCV Steam Generators Returned to Service With W
Defective Tubes (Section M8.1)
50-269,270,287/98-09-02 VIO No QA Records to Assure the Ability of EFW Pumps to Operate at Runout (Section E8.2)
50-269,270,287/98-09-03 URI Inaccurate EFW System Information in the UFSAR (Section E8.4)
Closed 50-287/97-01 LER Control Rod Drive System Short Circuit Results in a Reactor Trip Due to a Manufacturing Deficiency (Section 08.1)
50-269,270,287/97-14-02 VIO Failure to Adequately Implement Lee Station Procedure (Section 08.2)
50-269,270,287/97-14-03 VIO Failure to Provide Lockout Reset Instructions (Section 08.2)
50-269/97-06 LER Problems During Electrical Tests: Loss of Lee, Failure of Keowee 1, and Loss of Keowee 1 Auxiliaries (Section 08.2)
50-269,270,287/97-16-01 VIO Failure to Implement Nuclear Systems Directive 408, Testing (Section 08.3)
50-269/97-01 (Rev 0 & 1)
LER TS not met due to Deficient Procedures (Section 08.4)
50-269,270,287/98-01-01 URI Nuclear Safety Review Board (NSRB) Review of 10 CFR 50.59 Safety Evaluations (Section 08.5)
50-269,287/98-06-13 URI Potential Steam Generator TS Issues (Section M8. 1)
50-269/98-08 LER Steam Generator Tube ECT Indications Not Repaired Due to Inadequate Guidance Results in Operation Prohibited by Technical Specifications (Section M8.1)
50-269/97-16-06 VIO Inadequate Control of Modifications (Section M8.2)
50-269/98-02-06 URI Improperly Installed Valve Packing Gland Fasteners (Section M8.3)
50-270/96-005-01 LER Potential Uncontrolled Release Via Main Steam Relief Valves due to Inadequate Work Practice (Section M8.4)
50-269/98-01-00 LER Failure to Add New Keowee In-Service Test to Scheduling Process Results in Missed Surveillance (Section M8.5)
50-269,270,287/97-18-08 VIO Failure to Establish and Implement Procedures Three Examples (Sections M8.5 and M8.6)
50-269,270,287/97-18-09 IFI Review of the Root Cause Analysis for Agastat Time Delay and Type D87 Timer Relays (Section E8.1)
50-269,270,287/98-03-07 VIO Incorrect and Nonconservative Assumptions in Control Room Operator Dose Calculations (Section E8.3)
50-269,287/97-14-06 VIO Failure to Take Emergency Feedwater (EFW)
Recirculation Valve Corrective Action (Section E8.6)
50-269/97-14-08 VIO Inadequate Engineering Evaluation for Lifts Over Safety-Related Components (Section E8.7)
50-270,287/97-16-08 VIO Failure to Conduct Required Review of Test Results (Section E8.8)
50-270,287/97-15-09 VIO Failure to Update the UFSAR Regarding Fuel Enrichment (Section E8.9)
EA 97-298-06014 VIO Failure to Assure Design Configuration Control was Maintained for Letdown Storage Tank (LDST) Level Instrumentation Valves (Section E8.10)
50-269,270,287/96-03-04 IFI Installation of New Ground Detection Equipment (Section E.8 1)
50-269,270,287/98-02-12 VIO Failure to Adequately Review Calculations in the COLR (Section E8.12)
50-269,270,287/98-04-01 VIO Safeguards Information Container Found Unsecured and Unattended (Section S8.1)
Discussed 50-269/98-12 LER RBS NPSH Inadequate for Injection Mode (Section 02.4)
50-269,270,287/98-08-05 IFI EFW Potential Design Basis Issues (Section E8.2)
50-269,270,287/98-03-08 URI Licensing Basis Issues With Control Room Habitability (Section E8.3)
List of Acronyms AC Alternating Current B&W Babcock and Wilcox BSO Building Spray Operator BWST Borated Water Storage Tank CBWO Control Board Work Order CFR Code of Federal Regulations CM Corrective Maintenance COLR Core Operating Limits Report CRDM Control Rod Drive Mechanism CRIP Control Room Instrument Problem CRVS Control Room Ventilation System DC Direct Current EDF Energy Disposition Factor EFW Emergency Feedwater EOP Emergency Operating Procedure ESF Engineered Safety Feature F
Fahrenheit FLM Fluid Leak Management GL Generic Letter GPM Gallons Per Minute HPI High Pressure Injection HPSW High Pressure Service Water l&E Instrument & Electrical IFI Inspector Report IP Inspection Procedure IR
Inspection Report
KHP
Keowee Hydro-(electric) Plant
KHU
Keowee Hydro Unit
LDST
Letdown Storage Tank
LER
Licensee Event Report
Loss of Coolant Accident
Low Pressure Injection
MEPR
Major Equipment Problem Resolution
MM
Minor Modification
Non-Cited Violation
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
NSD
Nuclear System Directive
NSM
Nuclear Site Modification
Nuclear Safety Review Board
OEF
Operating Experience Feedback
Oconee Nuclear Station
Once Through Steam Generators
Operator Work Around List
Public Document Room
PIDS
Perimeter Intrusion Detection System
Problem Investigation Process
Preventive Maintenance
Post Modification/Maintenance Testing
Plant Operating Review Committee
Probabilistic Risk Analysis
pounds per square inch
Nuclear Security and Contingency Plan
Quality Assurance
RBACU
Reactor Building Auxiliary Cooling Units
Reactor Building Spray
REV
Revision
SITA
Self-Initiated Technical Audit
Selected Licensee Commitment
Security Procedures
SSEA
Safety System Engineering Audit
.
SSF
Safe Shutdown Facility
TEPR
Top Equipment Problem Resolution
TM
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
V
Volt
Vehicle Barrier System
Violation
Work Order