IR 05000269/1997016
| ML15118A287 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/26/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A285 | List: |
| References | |
| 50-269-97-16, 50-270-97-16, 50-287-97-16, NUDOCS 9802040399 | |
| Download: ML15118A287 (32) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287, 72-04 License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503 Report No:
50-269/97-16, 50-270/97-16, 50-287/97-16 Licensee:
Duke Energy Corporation Facility:
Oconee Nuclear Station, Units 1, 2, and 3 Location:
7812B Rochester Highway Seneca, SC 29672 Dates:
November 16 - December 27, 1997
.
Inspectors: Scott, Senior Resident Inspector S. Freeman, Resident Inspector E. Christnot, Resident Inspector D. Billings, Resident Inspector Approved by:
C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects Enclosure 2 9802040399 990126 PDR ADOCK 05000269 G
EXECUTIVE SUMMARY Oconee Nuclear Station, Units 1, 2. and 3 NRC Inspection Report 50-269/97-16, 50-270/97-16, and 50-287/97-16 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident inspectio Operations
During a high pressure injection flow test, the licensee discovered a leaking drain valve. The initial level of documentation of this problem was poor. Immediately following discovery, the licensee did not bound the problem or attempt to completely assess the scope of the problem prior to the onshift crew departing. These were considered weak investigative practices. Subsequent investigations were adequate and proposed activities were properly scoped. (Section 01.2)
Through a licensee initiated audit, additional potential problems were uncovered in the reactor building emergency sump flow paths. The licensee performed corrective actions to remove strainers, flanges, and insulation from all three buildings as applicable to assure present operability. Further follow up of this issue will be accomp lished through review of associated Licensee Event Report 50-269/97-10, which will address past operability. (Section 01.3)
During a three-hour closeout tour of the Unit 1 reactor building, the inspectors found the building in near-ready condition for power operations. Corrective actions from other previous closeout problems had been effective in improving the licensee's containment closeout proces (Section 01.4)
Results of physics testing of the new Unit 1 core, were satisfactor Operations and engineering controlled the evolution satisfactoril (Section 01.5)
The Unit 1 integrated control system testing was conducted in a well controlled and professional manner with thorough pre-job briefings and good evaluation of results. (Section 01.6)
A violation was identified involving the simultaneous testing of safety related electrical systems in two units that created a significant voltage transien (Section 02.1)
During the.return to service of Unit 1 reactor coolant pumps, a seal injection valve experienced a socket weld failure. The operators responded in a controlled manner to the failure, utilizing their off normal procedures. The licensee demonstrated good investigative techniques during the recovery period. (Section 02.2)
During post-maintenance testing, the licensee discovered that a primary core flood check valve leaked in excess of Technical Specification limits. The licensee had not performed intermediate checks of the
repaired valve prior to performing the post-maintenance testing. The lack of an interim check of work performance quality before valve re assembly was considered a procedural weakness. The licensee had no previous problems with these valves. Operational recovery efforts, reduced inventory control, and root cause analysis were good. Retesting indicated that the rework had been satisfactory. (Section 02.3)
A non-cited violation was identified for an inadequate procedure, which failed to prevent missing a required Technical Specification surveillance requirement. (Section 03.1)
The inspectors identified a violation for inadequate procedures. Three examples were identified that resulted in unexpected responses of operating systems. (Section 03.2)
Maintenance
The inspectors concluded that general maintenance activities were completed thoroughly and professionally. (Section M1.1)
The Units 1 and 2 post-modification low pressure service water full flow test adequately tested the system performance and was technically well managed by the system engineer. The operators involved with the test were well-briefed and conservatively responded during the testin (Section M1.2)
A non-cited violation was identified for failure to provide written instructions for changing the washers in the turbine driven emergency feedwater pump overspeed trip plunger. (Section M1.3)
A non-cited violation was identified for a failure to follow procedure when assembling a control rod drive mechanism after maintenanc (Section M1.4)
The inspectors concluded that the emergency power switching logic functional test was performed in accordance with the procedure and with supervisory and engineering oversight. The inspectors concluded that the problem identification process report appropriately addressed a deficiency involving a potential conflict between the test and the shutdown risk matrix. (Section M1.5)
The inspectors identified three examples of a violation for failure to properly control modifications. (Section M3.1)
Engineering
- .Current engineering guidance relative to Unit 1 reactor coolant pump operation at less than required net positive suction head was not clearly communicated to licenced operators. This was a training weakness in that site engineers did not change existing plant curves and that operations did not train their personnel appropriately in this are A violation was issued regarding a past engineering failure to translate the reactor coolant pump design details into plant operational
curves which contributed to impeller pieces being eroded, impacting plant operations. (Section E1.1)
The inspectors identified a violation for failure to conduct the required review of out-of-tolerance as-found conditions when test results did not meet acceptance criteria. (Section E8.1)
Plant Support
The inspectors identified a violation for an individual's failure to follow procedure for contamination contro (Section R1.1)
Report Details Summary of Plant Status Unit 1 began the period in a regularly scheduled refueling outage. On December 25, 1997, the unit was synchronized to the grid ending the outage at 98 days. The unit ended the period at 25 percent powe Unit 2 began and ended the period at 100 percent powe Unit 3 began the period at 100 percent power and decreased to 30 percent power on December 10, 1997, to remove insulation and strainers that potentially affected the emergency sump. The unit returned to 100 percent power on December 11, 1997, and remained at 100 percent power for the rest of the perio Review of Updated Final Safety Analysis Report (UFSAR) Commitments While performing inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and parameter I. Operations
Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operatiohs. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo.2 Unit 1 High Pressure Injection (HPI) Full Flow Test a. Inspection Scooe (61726)
On November 23, 1997. at 8:23 p.m., the licensee performed surveillance PT/1/A/0251/24, High Pressure I njection Full Flow Test. During that test, a drain valve on the 1B2 emergency injection line leaked wate The inspectors followed the licensee's investigation of this event inclusive of their corrective actions and walkdowns of the affected pipin b Observations and Findings As the test progressed to providing actual flow to the reactor coolant system (RCS), which was at atmospheric pressure, control room operators observed pressurizer (PZR) level begin to decrease and normal sump level increase. A non-licensed operator (NLO) entered the reactor building (RB) and found the valve cap for drain valve 1HP-334 on the floor with water flowing from the valve's open nipple. The NLO shut the leaking valve and replaced the pipe cap. The licensee completed the test. The operations shift gave a minimal writeup of the event in Problem
Investigation Process (PIP) Report 1-097-4206 and left the site without providing a detailed turnover on the even On November 24, 1997, the day shift engineers and operations personnel did not have sufficient information to make a thorough investigation of the problem. Answers to many questions regarding the as-found or discovered conditions were simply not available requiring after-the-fact disposition. The PIP report write-up discussed a serious line vibration associated with the drain valve without capturing a quantitative leve When questioned later, the NLO who closed valve 1HP-334 related that:
flow noise through the injection lines was very loud; the valve handwheel and retaining nut were very loose and vibrating on the cantilever of the stem; and the valve, once-closed, did not vibrate noticeably. The NLO tightened the handwheel nut multiple turns and closed the valve, which appeared to be about one turn open. This additional information cleared up the conclusion about a "serious line vibration."
During the evening of November 23, 1997, a technician was at the site to take vibrations on the injection line modification that was closer to the RCS than the subject valve. The 1HP-334 vibration level was not investigated during the shift of discovery using that technician. No effort had been made to document the valve cap status rior to the test. The 1HP-334 leakage value was not entered into the PIP report. Based on PZR level change, the leakage was calculated to be 15 gpm. Day shift personnel decided to wait for the return of the night shift crew or to call them at home to complete the investigation. This delay could have caused a loss of accurate transfer of event information. During the night shift of November 23 and 24, 1997, the surveillance was not re-run for event data corroboration and plant conditions were altered in that the RCS was closed up and filed to higher leve Thus, on day shift, the efforts of the previous night would have to be reversed to capture any further retesting. In a subsequent meeting, engineering identified that performing the test again would not be required at the time (see below interim and long-term actions).
Interim licensee correction actions were as follows:
Lock the handwheels of similar drain valves on all Unit 1 injection lines (1 HP-322, 323, 345, 326, 327, 328, and 334) with metal wir *
Check closed all the above valves (November 24, 1997).
- Liquid penetrant inspect the welds on all the above vents and drain *
Create an additional PIP report (1-097-4227) to address the effects of potential vibration upon valve 1HP-334 and related vent and drain valve *
Perform vibration level measurements during post-outage hot shutdown conditions with four reactor coolant pumps (RCPs)
operatin When checked, the above closed valves were found not to be open. The penetrant inspections of the valves revealed no weld defects. The 1HP 334 valve had been manipulated during the outage and was closed while in dry condition. PIP report 1-097-4206 contained more extensive long-term vibrational study action On December 21, 1997, the licensee performed vibrational examinations of the HPI piping with all four RCPs in operation. The vibration levels for valve 1HP-334 and other vent and drain locations were low. The inspectors reviewed the appropriate documentation. During "at pressure and temperature" hot shutdown RCS walkdowns of the reactor building (RB), the inspectors observed the metal lock wire on the injection line vent and drain valves' handwheels. The inspectors also observed that the injection lines were free of vibration during the tour. Further, the inspectors reviewed completed PIP report 1-097-4227 for operability of vents and drains, finding the documentation satisfactory with the valve vibration eliminated as a possible cause for the 1HP-334 leakag Similar valves in Units 2 and 3 were also addressed as being operabl Further, past operational and valve manufacture information indicated that this type of valve would not unseat under vibratio c. Conclusions During a high pressure injection flow test, the licensee discovered a leaking drain valve. The initial level of documentation of this problem was poor. Immediately following discovery, the licensee did not ound the problem or attempt to completely assess the scope of the problem prior to the onshift crew departing. These were considered weak investigative practices. Subsequent investigations were adequate and proposed activities were properly scope.3 Emergency Sump Issues a. Inspection Scope (37550, 71707, 62707)
On December 8, 1997, the Oconee engineering department submitted an operability form to the site operations staff indicating that new questions had been formulated about the operability of all three Oconee RB emergency recirculation flow paths. A Duke self-initiated technical audit team had posed these questions to the site engineering staff. The questions led to the identification of potential non-conservatism in existing calculations regarding the recirculation flow paths. The inspectors were notified of the questions during the evening of December 8, 1997, after the form was delivered to operations. The inspectors followed up on the evaluations, operational changes to the plants, and inspected the physical arrangements in the RB b. Observations and Findings It had been postulated that post-accident (loss of coolant) water level in the RB basement which would be available to the emergency sump would be less than previously calculated. The non-conservatism was not previously recognizing that water could be trapped in various places in
the RBs, particularly the reactor cavity and the deep end of the fuel transfer cana With the reduced water level in the RB basement, the emergency pump suction flow velocities would increase in the recirculation mode of pump operation. -Thus, the debris that had been previously assumed to be settling to the floor of the RB could be swept toward the sump (i.e., increased transportability).
This mobile debris could represent a larger contribution toward possible sump screen blockage (i.e., starve emergency core cooling pumps).
In the past, the licensee had installed strainers in the low point (deep end) drains of the refueling cavities. Under a postulated loss of coolant scenario due to debris, these strainers were thought to be potentially susceptible to being flow restricted. The debris could be in the form of loose paint and matter freed by the line break energ As indicated above, the clogged strainers could reduce the water available to the sumps. These strainers were not detailed in any modification package. On December 10, 1997, the licensee entered Unit 2 at power and removed the two strainers from the fuel transfer canal four-inch drains. On December 10, 1997, after a power reduction, the licensee entered Unit 3 and removed the fuel transfer canal strainer The Unit 1 strainers had been removed this outag The licensee had qualified, non-mirror insulation installed on the steam generator recirculation piping in the Units 1 and 3 RBs. Unit 2 did not have this insulation in place. Engineering conjectured that, due to the short distance from the emergency sump to this pi ing, should this insulation be hit by a direct stream of line break energy, it could be a major contributor to sump blockage. Coupled with the increased debris arriving at the sump, this total volume could jeopardize a sump recircul ation flow pat On December 10. 1997, at 1:00 p.m., the licensee issued a 10 CFR 50.72 notification (Number 33378) to the NRC regarding the above information potentially representing a condition outside of their design basis that could result in an inoperability of the emergency core cooling system The notification indicated that a Unit 3 power reduction was being conservatively initiated (1:10 p.m.). This reduction would facilitate removal of insulation, strainers, and a reactor cavity drain line flange (flange to a 4-inch drain off of the annular space between the reactor vessel and the interior shield wall that surrounds the vessel which drains to a 3/4-inch line leading to the normal RB sump). Operations reduced power to 30 percent for the entry. The 100 feet of piping insulation were removed. The 4-inch flange was not found to be installed as expected. The two strainers in the fuel transfer canal were removed. After the work to reduce recirculation path issues was complete, the unit power level was raised the next da On December 11, 1997, engineering completed their present operability evaluation for Units 2 and 3 finding them presently operable (PIP report 0-097-4395). This evaluation was reviewed by the NRC. with no concerns identifie A past operability evaluation was pending for the discovered RB
conditions that existed prior to December 9, 1997, when the licensee performed the strainer removal from Unit 2. During a phone conversion with the NRC on December 11, 1997, the licensee committed to issue a Licensee Event Report (LER) that will be used to track these issues (non-conservatism, unauthorized modifications, and past operability).
c. Conclusions Through a licensee initiated audit, additional potential problems were uncovered in the RB emergency sump flow paths. The licensee performed corrective actions to remove strainers, flanges, and insulation from all three buildings, as applicable, to assure present operability. Further follow up of this issue will be accomplished through the review of associated LER 50-269/97-10, which will address past operabilit.4 Unit 1 RB Inspection Tour at Hot Shutdown a. Inspection Scope (71707)
At hot shutdown, new licensee procedures directed inspection of the interior of the Unit 1 RB. The inspectors accompanied licensee personnel during their inspectio b. Observations and Findings On December 21, 1997, utilizing Procedure OP1/A/1102/001, Controlling Procedure for Unit Start Up, Enclosure 4.18A. Reactor Building Tour at Hot Shutdown, the inspectors and four NLOs toured the Unit 1 RB. The crew split into two groups, one for each side of the building. The intent of the inspection was the final closeout inspection of the building. At just above cold shutdown the previous day, a large cre including quality assurance personnel, performed their inspection and closeout. The inspectors and operators found approximately 10 items for additional repair or review actions. None of these items were major and this level of finding was much improved over previous containment closeouts. These items were submitted to the operations shift manager for disposition. The majority of the items were minor instrumentation leaks. Small amounts of oil were found on the main pump flanges of the 1B2 and 1A2 RCPs. The 1A2 RCP oil leak found by one inspector did require shutdown of the pump for upper bearing reservoir gasket replacement. This was identified as a rework item. Very few pieces of debris were found, and those identified were small in size. The coolant pumps were operating smoothly and with relatively low noise. No primary eaks or low-pressure service water leaks were observe c. Conclusions During a three-hour closeout tour of the Unit 1 RB, the inspectors found the building in near-ready condition for power operation Corrective actions from other previous closeout problems had been effective in improving the licensee's containment closeout proces II
01.5 Unit 1 Low Power Physics Testing a. Inspection Scope (61726, 71707)
On December-23, 1997, the licensee performed surveillance and testing of their newly installed core. The inspectors observed the majority of the activitie b. Observations and Findings Procedure PT/O/A/0711/01, Enclosure 13.7, Approach to Criticality, was the applicable instruction used by the licensee. The inspectors observed satisfactory testing of the new core. The only problem occurred early on in testing and involved group 5, rod 7. Specifically, after rod drop testing and re-latch, the rod would not pull with its group. The electronic controls, cabling, and stator motor checked out satisfactorily. After several hours of investigation, the licensee successfully re-latched the rod, unlatched it, and then re-latched it in group with no apparent difficultly. Although the licensee had no further problems with the rod, they wrote a PIP report on the occurrence. Tested parameters and expectations of the core were as predicted and met acceptance criteria. The operations staff worked well with the engineers during the testing and maintained good control over the evolutio c. Conclusions During physics testing of the new Unit 1 core, the test results were satisfactory. Operations and engineering controlled the evolution satisfactoril.6 Unit 1 Integrated Control System (ICS) Testing a. Inspection Scope (71707. 62707)
The licensee conducted three tests on the Unit 1 ICS during the Unit 1 power increase. The inspectors observed two of these test b. Observations and Findings The inspectors reviewed the procedures, attended the pre-job briefings observed the testing, and reviewed the data for ICS loss of power testing at 25 percent power and the electrical load rejection test from 25 percent powe The inspectors found the procedures adequately prepared to control the testing, collect data, deal with contingencies, and restore the unit to normal after testing. During the.pre-job briefings, the licensee gave a brief description of the testing, discussed the nuclear safety implications, discussed the roles and responsibilities of test and operations personnel, discussed management expectations for all participants, discussed contingencies, and gave opportunities for all
participants to ask questions. The inspectors found the actual testing to be conducted in a well controlled and a professional manner with good evaluation of results and all unknown occurrences explained before continuin c. Conclusions The Unit 1 ICS testing was conducted in a well controlled and professional manner with thorough pre-job briefings, and good evaluation of result Operational Status of Facilities and Equipment 02.1 Keowee Unit 1 Lockout During Engineered Safeguards Testing a. Inspection Scope (93702)
On December 1, 1997, during the performance of an engineered safeguards (ES) test on Unit 1 and a simultaneous performance of a 4160 volt breaker test on the Unit 3 main feeder bus (MFB), the Keowee Hydroelectric Plant (KHP) Unit 1 was inadvertently backfed from the Unit 3 MFB. The KHP Unit 1 was not operating, was in a normal standby lineup, and was electrically tied to the underground feeder. The inspectors reviewed procedures, the Nuclear Policy Manual, operator logs, and discussed the testing with licensee personne b. Observations and Findings The inspectors reviewed the following:
PT/0/A/0610/017, Operability Test of 4160 Volt Breakers
PT/1/A/0202/012, Component Test of Engineered Safeguards Channels
DWG OC-EL-PSL-19, CT4 Incoming Breaker (SK1) Logic Diagram
Operator logs for November 30 and December 1. 1997
Nuclear System Directive (NSD) 213, Conduct of Infrequently Performed Tests and Evaluations; Section 408, Testing; and Section 430, Shutdown Risk Management The inspectors observed the following:
The breaker operability test required that each breaker on the Unit 3 MFB be opened and closed, one at a time, in a step by step process, on a monthly basi *
The operability test stated in the precautions that many steps affect functional units of the emergency power switching logi ~The component test required that ES channels be manually tripped, proper component response be verified, and it be performed during
a refueling outag *
The component test stated in the precautions that the only unit affected is the unit in shutdown and tes *
The SKi logic diagram indicated that a live line-dead bus or dead line-live bus condition would give a permissive to close to SK *
The operator logs indicated that when the inadvertent backfeed occurred, a significant transient on the Unit 3 MFB was observed, numerous alarms were received, and low bus voltage indications were presen *
Specific nuclear system directives reference specific 10 CFR 50, Appendix B, criteria such as:
NSD.408, Testing, which stated, The purpose of this directive is to establish Duke Power Company s Nuclear Station Testing philosophy in accordance with 10 CFR 50 Appendix B, Criterion XI requirements."
- Subsection 408.6.10, Test Coordinator, of NSD 408, stated in part, each test coordinator shall be familiar with the assigned test procedure and any impacts that the test may have on other systems, prior to performing the tes Based on the reviews, observations, and discussions, the inspectors found the following:
The operability test and component test were performed in accordance with their respective procedure *
The close logic for the SKI breaker contained a dead line-live bus close permissive that actuated when the standby bus was energized from the Unit 3 MFB and an ES signal from Unit 1 was receive *
The inadvertent closing of the SKI breaker resulted in a significant voltage transient on the Unit 3 MFB and backfed/motorized the KHP Unit 1 generato *
Testing personnel were not aware of the logic interactio *
The licensee's evaluation determined that equipment had not been damaged during the transien NSD 408, Testing, requires that test personnel be familiar with any impacts that a test may have on other systems prior to performing the test. Failure to be aware of the logic interaction between the two test procedures is a violation (VIO) of 10 CFR 50 Appendix B. Criterion XI, and is identified as VIO 50-269,270,287/97-16-01: Failure to Implement Nuclear Systems Directive 408, Testin c. Conclusions A violation was identified involving the simultaneous testing of safety related electrical systems in two units that created a significant voltage transien.2 Unit 1 Reactor Coolant Pump (RCP) Seal Iniection Line Crack a. Inspection Scope (37550. 71707)
On December 6, 1997, a NLO on rounds heard a high-pitched noise and discovered an approximately two gallon per minute (gpm) leak on the 1A2 RCP seal injection line. The inspectors were informed of the problem and spent multiple inspection periods observing repair and investigative work. The unit was returning from a refueling outage with the plant between cold shutdown and hot shutdown. Four RCPs had been in operation for a short perio b. Observations and Findings After discussion and evaluation, the licensee secured flow through all Unit 1 seal injection lines. This left the running RCPs with no seal injection, but the seals were kept stable by component cooling wate This mode of pump operations was considered safe with the entry into several off-normal operational procedures (AP/1/A/1700/14 and 16, Loss of Normal Makeup and Letdown - Case A, Loss of Normal Makeu and Seal Injection, and Abnormal RCP Operation - Case C. Abnormal RCP Seal Injection, respectively). The plant was maintained at a constant temperature and pressure while a failure investigation process team investigated and directed repairs (PIP report 1-097-4371).
The licensee's team found that seal injection needle valve 1HP-65 made the noise heard by the NLO indicated above. Also, the team found that during the setting of the subject seal injection needle valves on December 6, 1997,. valve 1HP-65 had made a similar noise. The NLO who had performed the original valve adjustment had indicated that at the establishment of proper seal flow, the audible noise disappeared. None of the other valves had made a noise during the proces Removal of insulation around valve 1HP-65 revealed a crack in the upstream socket weld for the valve. The inspectors observed part of the removal, the crack, and the general piping arrangement. The valve and attached piping were removed (work order 97104524) and sent to a Babcock and Wilcox lab in Virginia with the cracked weld intact for root cause determination. Inspection results were due back in early January 199 A new valve was installed for 1HP-65. The inspectors evaluated pre installation cleanliness and weld preparations, and other general valve installation parameters. This valve was placed in service with engineering guidance and overview. The valve was vibrationally examined at various flow values, revealing no unexpected vibration levels. The other Unit 1 seal injection need e valves were placed into service and vibrationally examined, finding no anomalie c. Conclusions During the return to service of Unit 1 RCPs, a seal injection valve experienced a socket weld failure. The operators responded in a controlled manner to the failure, utilizing their off-normal procedure The licensee demonstrated good investigative techniques during the recovery perio.3 Unit 1 First Check Valve Off RCS Primary Leakage a. Inspection Scope (71707, 62707, 37550)
On December 8, 1997, during Technical Specification (TS) 4.5.1. surveillance testing, valve 1CF-14, the first check valve off the reactor vessel on core flood loop A, failed with higher than allowed TS 3.1.6.10 leakage. The licensee formed a failure investigation process team to evaluate the problem (PIP report 1-097-4390).
b. Observations and Findings During the Unit 1 outage, 1CF-14 had been repaired with fuel removed from the reactor vessel. The licensee had previously inspected the valve finding boric acid leakage on the hinge pin retaining nuts and body-to-bonnet joint. During the repair efforts, the licensee found the hinge pin had pitting behind one of the hinge pin nuts and decided to replace it. At that time, even though the valve internals had been removed, the licensee elected to not perform any blue check or other interim valve disk to seat leak tightness checks during re-assembly due to radiation exposure and other considerations. The valve was highly contaminated and in a difficult position to acces With fuel in the core, the plant below hot shutdown, and subsequent leak testing at about 750 psig, the valve leaked about 9.0 gpm (TS allowed leakage was 5.0 gpm). The licensee wrote a special test procedure to reseat 1CF-14 and retest the valve at a lower pressure. Two RCPs were cycled off and then on individually to move the valve's disk in an attempt to seat the valve more firmly. These attempts did not work and the licensee decided to completely depressurize and drain the primary loops to repair the valv Operational controls of the primary drain down to reduced inventory (about 10 inches on LT-5) were good. The licensee briefed personnel prior to the evolution before using a procedure written specifically for the work. A management meeting was he d to discuss the shut down risk and evaluate the procedure involved with the evolution. The procedure used an alternate shutdown cooling flow path through valves 1LP-105 and 1LP-19. This flow path was recommended by engineering to improve suction flow by increasing net positive suction head and to prevent possible air entrainment due to the piping configuration to the low pressure injection (LPI) pumps. Licensee management was present to observe the evolution. Extra shift personnel were directed to inde endently monitor core water level from monitors located at the back of the control roo Inspectors were on hand for the drain down and found the evolution well controlle The 1CF-14 valve was disassembled and inspected with the valve manufacturer representative present. Hardened deposits were found around the pinned joint between the disk and swing or pivot arm. The deposits appeared to be corrosion products. The inspectors observed the condition of the removed valve internals. For normal valve operation, the pinned joint had to allow rotation of the disk and pivoting of the disk on its pin. The deposits would allow rotation, but not pivotin The replacement of the hinge during the outage probably reduced free play in the disk assembly. Performance of a blue check or equivalent after replacement of the hinge pin would probably have detected the loss of pivot.capability. This lack of performance of an interim check was considered a procedural weakness. However, based on a search of the licensee's work records, the licensee had not experienced previous failures of these valves. In addition, the problem with the valve was found during post-maintenance testing, albeit at a time when its failure was more of an impact from a risk perspective (requiring a drain down to reduced inventory with fuel in the vessel to rework the valve).
After the investigation and repair, the valve was tested prior to complete re-assembly. The inspectors observed fit-up of the new disk and weld preparations for its attachment to the hinge. The licensee leak checked the new disk on its seat by putting water on top of the newly installed disk through the valve's open bonnet. The standing water did not leak between the disk to seat joint. Retesting at pressure revealed that the valve was leak tight. The inspectors reviewed the complete test documents, finding no problem c. Conclusions During post-maintenance testing, the licensee discovered that a primary core flood check valve leaked in excess of Technical Specification limits. The licensee had not performed interim checks of the repaired valve prior to performing the post-maintenance testing. The lac of an interim check of work performance quality before valve assembly was considered a rocedura weakness. The licensee had no previous problems with these va ves. Operational recovery efforts, reduced inventory control, and root cause analysis were good. Retesting indicated that the rework had been satisfactor Operations Procedures and Documentation 03.1 Inadequate Procedure for Technical Specification Surveillances on the Inadequate Core Cooling Monitor (ICCM)
a. Inspection Scope (71707).
The inspectors reviewed operating logs, PIP report 0-097-3784, LER 50 287/97-04, and Procedure PT/1,2,3/A/0600/01, Periodic Instrument Surveillanc b. Observations and Findings This issue was initially discussed in Inspection Report (IR)
269,270,287/97-15. According to the LER completed on November 25. 1997, the cause of the missed TS surveillance was that PT/1,2.3/A/0600/01 was an inadequate procedure. The procedure did not identify that the comparison of the ICCM and the operator aid computer subcooling margin monitor was a required TS surveillance requirement. The operator aid computer subcooling margin monitor had not been returned to service following the Unit 3 outage in March 1997 due to non-conservative inputs. Operations had been putting a daily note at the appropriate step in the surveillance procedure that the comparison of the operator aid computer subcooling margin (SCM) monitor and ICCM was "not applicable."
The operator's log stated that the "computer SCMs 0OS
[out-of-service] for program rewrite."
Operation's personnel did not realize this was a TS surveillance requirement. This was identified by the licensee following a change to the surveillance that caused operations to complete a more adequate review of the procedure. The monthly check had not been performed between March 1997 and October 1997. At this point of discovery, engineering developed an alternative method to verify the ICCM outputs and determined the points had not been out-of-tolerance. This method was to have operations complete a manual calculation using normal control room instruments. This non-repetitive licensee identified and corrected violation is being treated as a Non Cited Violation (NCV) consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50-287/97-16-02:
Inadequate Procedure Causes Failure to Complete Required Technical Specification Surveillance c. Conclusions A NCV was identified for an inadequate procedure which failed to prevent missing a required Technical Specification surveillance requiremen.2 Inadequate Procedures a. Inspection Scope (71707)
The inspectors reviewed requirements for procedure revision as discussed in NSD 703, Administrative Instructions for Station Procedures, and recent PIP reports dealing with incidents of inadequate procedure b. Observations and Findings Three examples of licensee failure to adequately review procedures and the impact of procedure changes were identified. These examples were identified by the licensee and captured in the PIP progra On December 21, 1997, during performance of OP/1/A/1102/001, Controlling Procedure for Unit Startup. Step 2.26 of Enclosure 4.18, loop 1A1 and 1A2 nozzle warming flow was found to be reading less than 0.2 gpm, which was outside the required flow band of 3-6 gpm. Investigation revealed that loop 1A1/1A2 nozzle warming throttle valve. 1HP-241. was close HP-241 was closed on December 12, 1997, during unit shutdown for the repair of 1CF-14, in accordance with Procedure OP/1/A/1102/10, Controlling Procedure for Shutdown, Enclosure 4.17, step 2.1.3. The procedure was exited prior to re-opening 1HP-241 and the HPI system startup procedure did not address 1HP-24 On November 29, 1997, operations,-personnel noted Unit 1 PZR level decreasing during performance of Procedure OP/1/A/1104/01 Enclosure 3.16, Filling Core Flood Tanks Using High Pressure Injection Pumps. In the cold shutdown mode, the letdown storage tank (LDST) is isolated by valve 1HP-78, LDST Inlet Isolation. During the procedure to fill the core flood tanks, valve 1HP-78 was opened. Investigation revealed that a previous procedure, OP/1/A/1104/04 Enclosure 3.10, Operation in Low Pressure Purification Mode, left valve 1LP-96, Low Pressure Supply to Purification Demineralizers Block, open. Procedure OP/1/A/1104/01 had not been reviewed in light of the other procedure's requirements. This line led from the LPI system to the inlet purification demineralizers upstream of the.LDST inlet. Approximately 700 gallons were transferred inadvertently from the PZR to the LDST by the discharge head of the LPI pump (200 psig). Operations closed 1LP-96 to stop the level decrease in the PZR. initiated PIP report 1-097-4270, and placed Procedure OP/1,2,3/A/1104/01 Enclosure 3.16 on administrative hol On December 1, 1997, operations identified that the normal Unit 1 makeup ath through Low Pressure Injection (LPI) was isolated. LPI was in the igh pressure mode of operation, which isolated the normal makeup path from the bleed holdup tanks. On discovery, operations realigned to the normal LPI mode which established the normal makeup flow path. The Technical Specification requirement was met in that an alternate makeup flow path was available while the high pressure mode of LPI was in service. This procedure had been used numerous times in the past with no problems because RCS leakage had been small enough to preclude use of normal makeup. At this time, increased RCS leakage had been occurring due to a cocked seal on one of the RCPs. This condition revealed an inadequate current and past procedure that could have had an impact on the system operatio NSD 703 specifies requirements which shall be met to ensure procedure changes are reviewed for impact on related or interfacing procedure The above examples of inadequate procedures indicate a deficiency in the procedure process. Failure to adequately establish these procedures resulted in a violation of TS 6.4.1 and is identified as VI0 50-269/97 16-03:
Inadequate Procedure c. Conclusions The inspectors identified a violation for inadequate procedure. Three examples were identified that resulted in unexpected responses of operating system Miscellaneous Operations Issues (92901, 92700)
08.1 (Closed) LER 50-270/96-02:
Failure to Reset Reactor Protective System Parameters Results In Operating Outside Design Basis Due to Inappropriate Action Following a dropped control rod, and an attempt to recover the control rod, personnel failed to reset the flux/flow imbalance setpoint. The circumstances involving this event were discussed in IR 50 269.270,287/96-10 and Violation 50-270/96-10-01, was issued. The violation was closed in IR 50-269,270,287/97-02. No new issues were identified in the LER. Based on the inspectors' review and the closure of the violation, this LER is close.2 (Closed) VIO 50-270.287/96-17-06:
Failure to Maintain Configuration Control The violation involved two examples of failing to maintain configuration control, one from operational activities and the other from maintenanc The Unit 1, 2, and 3 operations procedures for filling the RC OP/1,2,and 3/A/1103/02, were not written in enough detail to allow the operators to know when a proper vent was established on each hot le This resulted in a Unit 2 hot leg not being vented properl Additionally, an isolation valve to a Unit 3 RCS pressure switch was discovered closed following a calibration of the switch. This resulted in the switch not detecting RCS pressur For all three units, the licensee changed procedures for the filling and venting of the RCS, the draining and nitrogen purging of the RCS, and the periodic instrument surveillance procedures. The licensee also emphasized to all maintenance personnel the need to be aware of valve lineups for instrumentation. The changes involved adding enclosures and new steps to the procedures. The actions by the licensee have been effective in that subsequent filling and venting of the RCS have occurred with no identified deficiencies. Additional events involving closed isolation valves for instrumentation have not been identifie Based on the inspectors' reviews, the procedure changes, and the successful filling and venting activities, this item is close I Maintenance M1 Conduct of Maintenance M1.1 General Comments a. Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance activities:
OP/1/A/1106/006 Emergency Feedwater System - EFDWPT Overspeed Trip Test, Rev 88
- 15
PT/1/A/0251/024 HPI Full Flow Test
PT/1/A/0150/15D Enclosure 13.7, Intersystem LOCA Test
PT/0/A/0620/09 Keowee Hydro Operation
WO 97088231 Annual Outside Freeze Protection Preventive Maintenance
PT/1/A/0610/01J Emergency Power Switching Logic Functional Test
WO 97102894 Inspect KHP Unit 1 Field Breaker and Air Circuit Breaker (ACB) 3
PT/1/A/0251/023 Low Pressure Service Water (LPSW) System Flow Test
WR 97052520 1HP-65 Leak 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 use. Technicians were experienced and knowledgeable of their assigned tasks. The inspectors frequently observed supervisors and system engineers monitoring job progres Quality control personnel were present when required by procedure. When applicable, appropriate radiation control measures were in plac c. Conclusion The inspectors concluded that the maintenance activities listed above were completed thoroughly and professionall M1.2 Unit 1 LPSW Full Flow Test a. Inspection Scope (61726)
On November 16, 1997, with Unit 1 shutdown and Unit 2 at 100 percent power, PT/1/A/0251/023, LPSW System Flow Test, was performed on the recently modified pumps and system. New, enhanced impellers had been installed in the three pumps that serviced both units. The inspectors observed the LPSW test, flow parameters, and reviewed the data generated by the tes b. Observations and Findings After an extensive pre-job brief, the observed test was completed satisfactorily. With the system engineer on hand acting as test coordinator, the combined three pumps for Units 1 and 2 were flow tested under multiple conditions to all major components on both units. During the highest flow conditions, the valve flow stops on the flow control valves were set u.
During the testing, valve 1LPSW-252, a LPI cooler outlet flow control valve, did not react normally. This valve was noted as a test exception and was later fully investigated. The investigation was closely followed by the inspectors. The valve was replaced several days after the flow test. In the intervening period, its operability was adequately addresse During two-pump operation, with maximum flow being provided to both units' LPI coolers and the Unit 1 reactor building cooling units (RBCU),
operators increased flow to the Unit 2 RBCUs. During the increase, operators observed a low LPSW flow alarm to the Unit 2 RCP cooler Operators then reduced Unit 2 RBCU flow to clear the alarm. This possibility had been discussed in the pre-job brief. Operators developed a computer display of RCP parameters to monitor motor performance and flow was gradually increased with no further alarm The operators demonstrated good control over the evolution and a good understanding of the plan Aside from some required venting of flow instruments no other perturbations were observe c. Conclusions The Units 1 and 2 post-modification LPSW full flow test adequately tested the system performance and was well managed by the system engineer. The operators involved with the test were well-briefed and conservatively responded during the testin M1.3 Unit 1 Turbine Driven Emergency Feedwater (TDEFW) Pump Overspeed Setooint AdJustment a. Inspection Scope (62707)
The inspectors followed the circumstances surrounding the modification of the overspeed setpoint for the Unit 1 TDEFW pum b. Observations and Findings On November 17. 1997. during overspeed testing following modificatio the Unit 1 TDEFW pump tripped at 3650 revolutions per minute (rpm)
instead of the expected 3800-3850 rpm. The licensee made several adjustments to the modified overspeed trip mechanism, including replacing the mechanism, with the result that after each adjustment the overspeed trip setpoint remained lower than the acceptance criteri The licensee then reinstalled the original modified overspeed trip mechanism and made several adjustments to washers that determined preload on the spring in the overspeed trip plunger. The first adjustment resulted in an overspeed trip of 3792 rpm. After the next adjustment the turbine unexpectedly reached 3900 rpm without tripping and operators manually tripped the turbine. The licensee determined this higher speed did not damage the turbine and was caused when one of the washers had been improperly installed. The licensee corrected the washer installation, retested the turbine, and found it to trip at the expected speed. The licensee determined the improper installation occurred because written instructions were not available for adjusting
the washers on-the overspeed trip plunger. The licensee subsequently changed procedures to include these instruction The inspectors reviewed Procedure MP/0/A/1320/004, Overspeed Trip Plunger Inspection and/or Replacement, Revision 8. and interviewed personnel involved in activities associated with the turbine driven emergency feedwater pump wor Based-on this, the inspectors determined the failure to provide written instructions for changing the washers in the overspeed trip plunger constituted an inadequate procedure and was a violation of TS 6.4.1.e. This non-repetitive, licensee-identified, and corrected violation is being treated as a NCV, consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50 269/97-16-04:
Inadequate Procedure for Turbine Driven Emergency Feedwater Pump Overspeed Trip Plunge c. Conclusions A NCV was identified for a failure to provide written instructions for changing the washers in the TDEFW pump turbine overspeed trip plunge M1.4 Coupling of Control Rod Drive Mechanism (CRDM) 59 a. Inspection Scope (62707)
The inspectors followed the circumstances surrounding the Babcock and Wilcox Owners Group life extension work on CRDM 5 b. Observations and Findings During the life extension work on CRDM 59. vendor personnel removed the CRDM from the reactor head, disassembled it, and measured it for wea Vendor personnel then reassembled and installed the CRDM. The licensee attempted to couple the CRDM after reactor assembly and found that the leadscrew of the CRDM would not lower fully into the control rod hu Upon investigation, the licensee determined that vendor personnel had installed the torque taker into the CRDM with the wrong orientation when reassembling the CRDM. The licensee documented the inappropriate action in PIP report 1-097-4136, removed the CRDM, corrected the orientation of the torque taker, and reinstalled the CRD The inspectors reviewed the vendor procedures and the PIP report, determining that the inappropriate action constituted a violation of 10 CFR 50 Appendix B, Criterion V for failure to follow procedure. This non-repetitive, licensee-identified and corrected violation is being treated as a NCV, consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50-269/97-16-05:
Failure to Follow Control Rod Drive Maintenance Procedur c. Conclusions A NCV was identified for a failure to follow procedure when assembling CRDM 59 after maintenanc M1.5 Emergency Power Switching Logic Functional Test a. Inspection Scooe (61726)
The inspectors observed, reviewed, and discussed the results of the emergency power switching logic functional test with licensee personne b. Observations and Findings The activities were controlled by procedure PT/1/A/0610/001J, Revision 29. The purpose of the procedure was to verify that the emergency power switching logic functions to maintain the Unit 1 main feeder bus (MFB)
energized by the most reliable source without operator action. The sources were in the following order:
The initial conditions were with the MFB 1 and MFB 2 on the normal auxiliary transformer, 1 *
.The first transfer was from 1T to the startup transformer, CT1, with load shed not initiate *
The second transfer was from CT1 to the Lee Steam Station through transformer CT5. with load she *
The third transfer was from CT5 to KHP, through the overhead line to the switchyard, through the underground line to transformer CT4, with load she *
Two additional load sheds were performed using engineered safety signal The inspectors noted some deficiencies with the procedure, which involved the following:
During the pre-job briefing, operators noted that the procedure required the underground feeder and the standby shutdown facility (SSF) be out of services at the same time. This was a double red area in the shut down risk matri *
During performance of the initial portion of the test, power to support the data collection instruments was from Unit 1, and when the transfer with the loss of non-vital loads occurred, this power was los *
During the test, the inspectors observed that breaker 15, 1A Chiller Motor, on the 1TE 4160 V switchgear, was closed when the procedure indicated that it should have tripped ope *
Section 12.26 of the test required the verification of voltage on the trip coil for breaker 10, 1C LPI Pump Motor, on the ITE 4160 V switchgear, and no voltage was presen The inspectors observed actions taken by the licensee and reviewed the completed test procedure and noted the following:
Prior to test performance, a plant operating review committee (PORC) meeting was held via telephone to discuss the shutdown risk matrix and the procedure interfac *
The power used to support the data collection instruments was rerouted to Unit 2 power sources prior to the instruments being needed later on in the tes *
The 1A chiller motor breaker should have been listed as not applicable for tripping during the test. (This was indicated to be a deficiency.)
- Post-surveillance special test procedure TT/1/A/0610/029, Verify Trip Coil for 1TE 10, Revision 0. was performed to verify trip coil voltag The PORC indicated that the procedure did not address the shutdown risk matrix and it should have. The PORC gave permission to have both the SSF and the KHP underground power feed out of service for the duration of the test. The special test was completed satisfactoril The inspectors observed that a PIP report (0-097-4163) was issued concerning the deficiency involving the interface with the shutdown risk matri c. Conclusions The inspectors concluded that the test was performed in accordance with the procedure with supervisory and engineering oversight. The inspectors concluded that the PIP report addressed a test deficiency involving the interface with the shutdown risk matri M3 Maintenance Procedures and Documentation M3.1 Unauthorized Design Changes During Maintenance a. Inspection Scope (61726)
The inspectors reviewed requirements for control of modifications as discussed in NSD 301, Nuclear Station Modifications, Revision 13, and problem reports dealing with modifications of plant systems and component b. Observations and Findings Three examples of licensee failure tocontrol plant modifications through maintenance activities were identified. These examples were identified by the licensee and captured in the PIP progra On September 26, 1997, the licensee identified that during maintenance activities on 1LPSW-15, the wrong size lug for the conductor was installed. Additionally, the butt splice of the cable was not taped with the proper material and did not meet the requirements of the environmental qualification program. A work history review identified that the last maintenance in this area was performed in May 1994. The wiring was evaluated as operable and PIP report 1-097-3191 was initiate On October 23, 1997, during maintenance work on the 1B2 RCP, maintenance personnel discovered bolts of two different sizes connecting flanges on the permanent piping. The bolts found were 7/8-inches and the required size was 1-inch. This was the second occurrence of the wrong size bolts being installed with the previous problem occurring on the same pump flange in Unit 2. An operability evaluation was completed in PIP report 1-097-3715 and concluded the pump was past operabl On November 16, 1997, a piece of stainless steel tubing was found connected between a vent and a drain valve on the HPI line. The tubing was found during maintenance troubleshooting of a seal leakoff problem on the Unit 1 RCPs. The tubing was not identified on any drawing or any modification. Licensee personnel removed the tubing and initiated PIP report 1-097-4088 to identify the issue. The tubing was evaluated as past operabl NSD 301 specifies requirements that shall be met to 'implement modifications. These examples of modifications completed on Unit 1 systems and components without proper documentation indicate a breakdown in the modification process. Failure to properly control modifications is a violation of 10 CFR 50, Appendix B. Criterion III. Design Control and is identified as VIO 50-269/97-16-06:
Inadequate Control of Modification c. Conclusions The inspectors identified three examples of a violation for failure to properly control modification M8 Miscellaneous Maintenance Issues (92902)
M (Closed) Inspector Follow uo Item (IFI) 50-269.270.287/96-20-02:
Unfiltered Motors This IFI concerned the fact that all safety-related motors at Oconee did not have filter screens on their air intakes and were not internally cleaned on a routine basis. The inspectors followed the licensee's actions on this NRC identified issu Per PIP report 0-096-2478, PIP report 0-097-205, and Oconee Site Engineering Memorandum dated December 18, 1997. the licensee initiated a
- lan to clean all motors. This preventive maintenance effort has been inked with Duke corporate efforts. The licensee generated standing work orders to support cleaning that will be replaced by a preventive
maintenance program change. This item is close III. Engineering El Conduct of Engineering E1.1 Unit 1 Reactor Coolant Pump Impeller Evaluation a. Inspection Scope (37551, 92903)
As indicated in IR 50-269,270,287/97-15 (Section M1.2). the licensee had undertaken an evaluation of impeller as-found conditions on three of the Unit 1 RCPs including the parameters for RCP operation. At the same time, the licensee addressed net positive suction head (NPSH)
requirements on the other Oconee units that have different RCPs. The inspectors conducted independent reviews of the licensee's evaluation, and the UFSAR; reviewed video tape inspections of the RCPs: and discussed the problems with the licensee and appropriate NRC personne b. Observations and Findings Licensee PIP report 1-097-3613 and calculations OSC-7046, Unit 1 RCS Operability for Cycle 18 - RCP Impeller Cavitation Damage and OSC-7041, Evaluation of RCP NPSH Available, contained the details on the RCP impeller cavitation problem. The OSC-7046 calculation addressed the reasons for the material loss from the impeller castings and concluded that the pumps were operated at an NPSH less than that required to prevent cavitation since initial plant startup. This resulted in material loss from the impellers with cavitation erosion that caused impeller imbalance, holing of impeller vanes, and then weakening of one of the vanes on RCP 1A1 until part of the weakened vane separated under fatigue loading. According to the licensee, this operational oversight occurred for two reasons. First, misunderstanding the impact of the pressure instrumentation location on the achieved pressure values prior to pump operation. Typically, pressure was maintained at 275 psig for the first pump start, but due to the pressure drop across the steam generator, the actual NPSH seen at the RCP in single pump operation was 175 psig. Second, by.plant design and NPSH requirements for the installed Westinghouse pumps, the first pump started and the last pump secured were starved for NPSH. Additionally, with LPI in operation to cool the reactor plant, the RCS could not be brought to a pressure higher than NPSH minimum due to the LPI piping design pressure limitation (300 psig). This piping, which was normally isolated at a different point in the startup, could be damaged at an actual minimum NPSH pressur The first Unit 1 pump started was usually the 1A1 RCP to provide PZR spray capability. First pump start or last pump off percent of run times at less than required NPSH were: 63, 25, 6.5, and 5.5 percent for the 1A1, 1B2, 1B1, and 1A2 RCPs, respectively. These times roughly correlated to the observed degree of cavitation damage. RCP 1A1 was replaced during the outage. The aforementioned licensee documentation found the impellers of RCPs 1A2, 1Bi, and B2 acceptable for use through
the current fuel cycle. The NRC found no reason to refute the conclusions of the licensee. At the end of the current Unit 1 outage, the licensee proposed and implemented adjunctive actions for the use of the existing impellers such as eliminating five minute RCP runs at low plant pressure and temperatures from the start up procedures and then minimizing run time of the RCPs in the low NPSH period Additionally, component engineering guidance provided a start sequence for the RCP Regarding the impeller failure on RCP 1AL, PIP report 1-097-3613 also addressed the licensee's interpretation of the maintenance rule. The text of the PIP report stated in part:
"This event is a Maintenance Preventable Functional Failure. As stated in the Problem Evaluation, the apparent cause of the loss of the impeller vane material is cavitation damage from high flow, low suction head, single pump operations....The root cause(s) of this failure are: 1.) Inappropriate operating range -- If the pumps were not operated in off-design conditions, cavitation would not occur: 2.) Inadequate preventive maintenance -- Although industry precedence and vendor guidance do not suggest that
"routine" inspection/replacement of RCPs is necessary, it is obvious that this pump should have been replaced sooner."
The pumps installed in Unit 1 (and not the other two units) required unachievable NPSH within the design constraints of the plant. However, this could have been managed better with more refined operational and administrative controls such as those instituted in part during the recent restart. In particular, the Unit 1 wide and ow range cooldown and heat up curves that were provided in procedure OP/0/A/1108/01, Enclosure 3.28, specified required values of NPSH less than those required to prevent cavitation of the RCPs.- The operators used these 1994 (last update, calculation OSC-5615. Error-Adjusted RCP NPSH Curves, dated 4/15/94) and earlier graphs to maintain pressure and temperature of the RCS. This failure to provide accurate graphs for plant operation violated the requirements of 10 CFR'50 Appendix B. Criterion III, Design Control, in that design bases were not correctly translated into specifications, drawings, procedures and instructions. Failure to translate critical operational specifics that resulted in a loss of part of an impeller into the lower part of the reactor vessel is a violation of these requirements and is identified as VIO 50-269/97-16-07:
Failure to Translate RCP NPSH Requirement At the beginning of the preparations to return to power, the inspectors reviewed implementation of corrective action regarding RCP operatio The wide and low range heat up and cooldown curves still had a lower than required NPSH values cited in the engineering provided curves. The inspectors questioned the operators about the lack of change in the curves. Two operations shift managers and a senior reactor operator indicated that they did not know that the curves were in error. Upon receiving a negative response to that question, the inspectors asked if the operations personnel understood the new single pump run time minimization statements presently found in startup procedures. The operators did not know that the intent of the procedure changes was to
limit further damage to the existing RCP impellers. The discussions in the guidance provided by engineering had not reached the operator When site management was informed of this observation, the pertinent operations procedures were placed on administrative hold and training material was generated to inform the operators of the RCP impeller investigation findings and the intent of the pump run minimization statements. At the time of this observation, no excessive RCP run times had accrued. This training issue pointed out a weakness in the process of communicating information to the operators. The licensee enhanced the procedures to communicate more clearly their inten Engineering had not changed the heat up and cooldown curves due to several issues. First, due to the design and operations issues discussed above, the curves could not be readily changed to allow the pumps to be operated in a non-cavitation state. Engineering was still indeterminate on a specific direction for the curves. Several other changes were forthcoming on the subject curves and an intermediate change would not solve those issues. By direction provided in the above-mentioned documentation, engineering planned to collect:
RCP run time, correlated plant pressure, and plant temperature data to perform an end-of-cycle calculation on the viability of the existing RCP impellers. Therefore, the involved engineers knew of the lack of adequate NPSH operations for this cycle. Philosophically, operations personnel rely on plant curves and expect them to be accurate. Clearly, engineering did not support the operators who need curves to effectively maintain the plant. If directed in advance, the operators could maneuver the plant closer to the minimum NPSH without damaging the LPI piping. This lack of clear knowledge provided by the existing plant curves supports the violation as stated abov c. Conclusions Current engineering guidance relative to Unit 1 RCP operation at less than required NPSH was not clearly communicated to licensed operator This was a training weakness in that site engineers did not change existing plant curves and that operations did not train their personnel appropriately. A violation was issued regarding a past engineering failure to translate the RCP design details into plant operational curves which contributed to impeller pieces being eroded, impacting plant operation E8 Miscellaneous Engineering Issues (92903)
E8.1 (Closed) Unresolved Item (URI) 50-269,270,287/97-12-03: Relay As-Found Conditions This item was opened when technicians found setpoint values for degraded grid undervoltage relays 27YBDGX, 27YBDGY, and 27YBDGZ out of tolerance and did not notify engineering of the condition. At the time, licensee procedures permitted the option of not reporting the out-of-tolerance as-found condition if the condition resulted from a procedure chang The item was unresolved pending review of: (1)
the administrative requirements for documentation and evaluation of as-found test
conditions; and (2)
the determination of the extent to which the option of not reporting an out-of-tolerance as-found condition existe To determine the administrative-requirements for documentation and evaluation of as-found conditions, the-inspectors reviewed the following:
NSD 203, Operability, Revision 8: NSD 219, Electrical Device Calibration Out of Tolerance, Re-vision 0; and NSD 307, Quality Standards Manual, Revision 13. NSD 203, Appendix A, stated that equipment important to safety found out-of-tolerance was to be expeditiously evaluated for the consequences of the out-of-tolerance condition. NSD 219, Section 219.1, provided requirements for meeting NSD 203, Appendix A. Section 219.5 defined out-of-tolerance to be when data obtained from calibration exceeds the tolerance specified in the applicable plant procedures. NSD 307, Appendix B stated that degraded gri.d undervoltage relays 27YBDGX, 27YBDGY, and 27YBDGZ were safety-related equipment. On August 18. 1997, the as-found setpoint values for each of these relays exceeded the tolerance specified in the procedur To determine the extent of the condition, the licensee reviewed procedures and determined that approximately 60 electrical procedures included the option of not reporting an out-of-tolerance as-found condition if the condition resulted from a procedure change. The licensee has begun changing these procedures to remove this option and has revised their setpoint change process to require an as-found evaluation on setpoint change Licensee Topical Report, Quality Assurance Program, which implements 10 CFR 50 Appendix B, requires that where test results do not meet test acceptance criteria, a review be conducted to determine the cause, required corrective action, and retest as necessary. Failure to conduct the required review of out-of-tolerance as-found conditions is a violation of 10 CFR 50 Appendix B, Criterion XI and is identified as VIO 50-269,270,287/97-16-08: Failure to Conduct Required Review of Test Result I Plant Support Areas R1 Radiological Protection and Chemistry Controls R1.1 Failure to Follow Procedures for Contamination Control a. Inspection Scope (71750)
The inspectors observed the radiological practices of personnel exiting the radiation control area (RCA) at the Unit 2 control roo b. Observations and Findings On December 8, 1997, the inspectors observed an individual exiting the RCA without completing a survey of their person for possible
contamination. The individual stepped across the magenta and yellow boundary tape at the contamination monitors without performing a survey for contamination. When questioned by the inspectors, the individual stated that he had not been anywhere to get contaminated. The inspectors explained that a contamination survey was required anytime an individual crossed the boundary when exiting an RCA. The individual then completed a contamination survey through the monitors. No contamination was detecte The inspectors notified radiation protection management. The individual was counseled and further questioning revealed that he did not recognize that he had entered the RCA. The inspectors determined that the individual failed to follow Procedure 111-8, Personnel Contamination Monitoring, when exiting the RCA on December 8, 1997. Failure to adhere to procedures for contamination control is a.violation of 10 CFR 20 and is identified as VIO 50-269,270.287/97-16-09: Failure to Follow Procedure for Contamination Contro c. Conclusions The inspectors identified a violation for an individual's failure to follow procedure for contamination contro 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 January 5. 1998. The licensee acknowledged the findings presented. No proprietary information was identified to the inspector *
Partial List of Persons Contacted Licensee E. Burchfield, Regulatory Compliance Manager T. Coutu, Scheduling Manager, D. Coyle, Mechanical Systems Engineering Manager T. Curtis, Operations Superintendent B. Dobson, Mechanical/Civil Engineering Manager W. Foster, Safety Assurance Manager D. Hubbard, Maintenance Superintendent C. Little, Electrical Systems/Equipment Engineering Manager W. McCollum, Vice President, Oconee Site M. Nazar, Manager of Engineering B. Peele, Station Manager J. Smith, Regulatory Compliance J. Twiggs, Manager, Radiation Protection Other licensee employees contacted during the inspection included technicians, maintenance personnel., and administrative personne NRC
. LaBarge, Project Manager Inspection Procedures Used IP 37550 Engineering IP 61726 Surveillance Observations IP 62707 Maintenance Observations IP 71707 Plant Operations IP 71750 Plant Support Activities IP 92700 Onsite Follow-up of Written Event Reports IP 92901 Follow-up - Plant Operations IP 92902 Follow-up - Maintenance IP 92903 Follow-up - Engineering IP 93702 Prompt Onsite Response to Events
Items Opened, Closed, and Discussed Oened 50-269,270,287/97-16-01 VIO Failure to Implement Nuclear Systems Directive 408, Testing (Section 02.1)
50-287/97-16-02 NCV Inadequate Procedure Causes Failure to Complete Required Technical Specification Surveillances (Section 03.1)
50-269/97-16-03 VIO Inadequate Procedures (Section 03.2)
50-269/97-16-04 NCV Inadequate Procedure for Turbine Driven Emergency Feedwater Pump Overspeed Trip Plunger (Section M1.3)
50-269/97-16-05 NCV Failure to Follow Control Rod Drive Maintenance Procedure (Section M1.4)
50-269/97-16-06 VIO Inadequate Control of Modifications (Section M3.1)
50-269/97-16-07 VIO Failure to Translate RCP NPSH Requirements (Section E1.1)
50-269,270.287/97-16-08 VIO Failure to Conduct Required Review of Test Results (Section E8.1)
50-269,270,287/97-16-09 VIO Failure to Follow Procedure for Contamination Control (Section R1.1)
Closed 50-270/96-02 LER Failure to Reset Reactor Protective System Parameters Results In Operating Outside Design Basis Due to Inappropriate Action (Section 08.1)
50-270.287/96-17-06 VIO Failure to Maintain Configuration Control (Section 08.2)
50-269,270.287/96-20-02 IFI Unfiltered Motors (Section M8.1)
50-269,270,287/97-12-03-URI Relay As-Found Conditions (Section E8.1)
List of Acronyms ACB Air Circuit Breaker CFR Code of Federal Regulations CRDM Control Rod Drive Mechanism ES Engineered Safeguards F
Fahrenheit GPM Gallons Per Minute HPI High Pressure Injection ICS Integrated Control System ICCM Inadequate Core Cooling Monitor IFI Inspector Follow up Item IR
Inspection Report
KHP
Keowee Hydroelectric Plant
LDST
Letdown Storage Tank
LER
Licensee Event Report
Low Pressure Injection
Low Pressure Service Water
MFB
Main Feeder Bus
Non-Cited Violation
Non-Licensed Operator
NRC
Nuclear Regulatory Commission
NSD
Nuclear System Directive
Public Document Room
Problem Investigation Process
Plant Operating Review Committee
Pounds er Square Inch Gauge
Performance est
PZR
Pressurizer
Reactor Building
RBCU
Reactor Building Cooling Unit
Radiation Control Area
Reactor Coolant Pump
Revolutions Per Minute
SCM
Subcooling Monitor
SSF
Standby Shutdown Facility
Turbine Drive Emergency Feedwater
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Violation
Work Order
Work Request