IR 05000206/1988019
| ML13316B941 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 09/15/1988 |
| From: | Andrew Hon, Huey F, Johnson P, Tatum J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13316B938 | List: |
| References | |
| 50-206-88-19, 50-361-88-19, 50-362-88-20, IEB-85-003, IEB-85-3, NUDOCS 8810030232 | |
| Download: ML13316B941 (17) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report No /88-19, 50-361/88-19, 50-362/88-20 Docket No, 50-361, 50-362 License No DPR-13, NPF-10, NPF-15 Licensee:
Southern California Edison Company P. 0. Box 800, 2244 Walnut Grove Avenue Rosemead, California 92770 Facility Name:
San Onofre Units 1, 2 and 3 Inspection at:
San Onofre, San Clemente, California Inspection conducted:
July 3 through August 16, 1988 Inspectors:
A7/1, A/
Tk F.,/Hkey, Senior Resident Inspector Date Signed Units, 2 and 3 C'. Ta.tum, Resident Inspector A. L. Hic,
esident InspectorDaeSgd Approved By:
T P. H. Johnson, Chief Date A. L H, nspetorDate Signed Reactor!'Projects Section 3 Inspection Summary Inspection on-July 3 through August 16, 1988 (Report Nos. 50-206/88-19, 50-361/88-19, 50-362/88-20)
Areas Inspected:
Routine resident inspection of Units 1, 2 and 3 Operations Program including the following areas:
operational safety verification, radiological protection, security, evaluation of plant trips and events, monthly surveillance activities, monthly maintenance activities, independent inspection, licensee event reports review, and followup of previously identified item Inspection procedures 30703, 61726, 62703, 71707, 71709, 71710, 71881, 90712, 92700, 92701, 93702 were covere Safety Issues Management System (SIMS) Items:
None 8810030232 980915 PDR ADOCK 05000206 PNU
II-2 Results:
General Conclusions and Specific Findings:
1. The inspectors observed two examples of operator inattention to detail (paragraphs 4.a and 4.d), and one example of commendable operator performance (paragraph 4.c).
2. Weaknesses were noted in the resolution of two nonconformance reports (paragraphs 4.b and 10.d).
Summary of Violations:
1. Maintenance personnel installing a temporary pump to transfer water from the Unit 3 reactor vessel lower cavity to the spent fuel pool did not follow a precaution in the approved maintenance order, which resulted in a water siphoning event (paragraph 10.c).
Open Items Summary:
During this report period, 13 items were closed, 5 items were opened and 1 was examined and.left ope DETAILS Persons Contacted Southern California Edison Company C. McCarthy, Vice President, Site Manager
- H. Morgan, Station Manager D. Heinicke, Deputy Station Manager
- D. Schone, Quality Assurance Manager D. Stonecipher, Quality Control Manager
- R. Krieger, Operations Manager
- D. Shull, Maintenance Manager
- J. Reilly, Technical Manager P. Knapp, Health Physics Manager D. Peacor, Emergency Preparedness Manager P. Eller, Security Manager J. Reeder, Operations Superintendent, Unit 1 V. Fisher, Operations Superintendent, Units 2/3
- L. Cash, Maintenance Manager, Unit 1
- R. Santosuosso, Maintenance Manager, Units 2/3 C. Chiu, Assistant Technical Manager
- M. Wharton, Assistant Technical Manager
- C. Couser, Compliance Engineer
- Denotes those attending the exit meeting on August 16, 1988.
The inspectors also contacted other licensee employees during the course of the inspection, including operations shift superintendents, control room supervisors, control room operators, QA and QC engineers, compliance engineers, maintenance craftsmen, and health physics engineers and technician. Plant Status Unit 1 Unit 1 completed a 172-day mid-cycle outage on August 6, 1988. The outage was extended 128 days to resolve environmental qualification problems. Except for periodic power reductions to clean condenser water boxes, the unit operated without incident for the remainder of the perio Unit 2 Unit 2 operated at full power during this report perio Unit 3 Unit 3 completed a 103-day refueling outage on August 15, 1988. The outage was extended approximately three weeks to repair a shutdown cooling isolation valve and replace a reactor coolant pump sea. Operational Safety Verification (71707)
Radiological Protection (71709)
Security (71881)
The inspectors performed several plant tours and verified the operability of selected emergency systems, reviewed the tag out log and verified proper return to service of affected components. Particular attention was given to housekeeping, examination for potential fire hazards, fluid leaks, excessive vibration, and verification that maintenance requests had been initiated for equipment in need of maintenance. The inspectors also observed selected activities by licensee radiological protection and security personnel to confirm proper implementation of and conformance with facility policies and procedures in these area No violations or deviations were identifie.
Evaluation of Plant Trips and Events (93702) Nuclear Instrumentation Calibration Error (Unit 1)
On August 9, 1988, while the Unit was at 90% in power ascension testing after the mid-cycle outage, the licensee discovered that several daily calorimetric power calibrations were in error. This resulted in indicated power on the nuclear instrumentation system (NIS) being adjusted as much as 4% lower than actual reactor powe The error was caused by one of three feedwater flow indicators, which provided flow indication that was lower than actual feedwater flow. The licensee determined that the flow orifice for the deficient flow indicator was installed backwards, causing indicated flow to be less than actual flo The licensee determined that there was no safety significance associated with this deficiency because the margins used in the safety analysis and the reactor trip set point were conservativ The licensee also evaluated the impact that this deficiency had on plant operations, such as feedwater control, and did not identify any significant effects. In the interim, the calorimetric procedure was revised to use three times the highest indicated feedwater flow of the three loops as the total feedwater flow so the calculated thermal power would be conservatively hig The inspector raised the following concerns:
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Although the operator was following the calorimetric procedure correctly, he failed to recognize and question the difference in feedwater flow among the three loop It would seem prudent to include extra margin in the calorimetric calculations to account for increased uncertainty at low power level The licensee acknowledge the inspector's concerns and committed to enhance the calorimetric procedure by requiring the user to compare
feedwater flow in the three loops for anomalies and to include penalty factors in the :calculation during power ascension. The licensee was evaluating the cause for the improper installation of the flow orifice during the mid-cycle outage. The licensee's maintenance practices and responses to the concerns identified above will be examined further during a future inspection. This item is unresolved (50-206/88-19-01).
b. Air Binding of High Pressure Safety Injection Pump 3P-018 (Unit 3)
On July 20, 1988, with the unit in Mode 5 (cold shutdown), high pressure safety injection (HPSI) pump 3P-018 became air bound when it was operated to raise pressurizer leve The pump was operated for approximately 15 minutes with no flow before it was secure Shortly after the pump was started, the control operator received reports that a loud bang was heard. Nonconformance report (NCR)
3-2117 was issued to document actions taken to address this problem and to evaluate the cause of HPSI system air binding. The following actions were documented:
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HPSI system piping was vented to remove all ai Inservice testing was completed on 3P-018 and no abnormal conditions were identifie HPSI system piping was walked down and inspected -for damag Although several discrepant pipe supports were identified and documented on additional NCRs, these conditions were not believed to be associated with this even The licensee's preliminary root cause for HPSI system air binding concluded that the most probable cause was undocumented maintenance or valve manipulations that drained some portion of the HPSI pipin The licensee also concluded that the loud banging noise was due to check valve slam associated with the idle HPSI pump discharge stop check valve. The inspector made the following observations relative to the licensee's conclusions:
Just prior to this event, Unit 3 containment was being pressurized in preparation for the integrated leak rate test (ILRT).
Pressure in containment was approximately 52 psig and preliminary data indicated that there was an air leak. After emergency sump isolation valves 3HV-9302 and 3HV-9303 were torqued closed an additional two turns each, the air leak appeared to stop. This indicated that these valves.were leaking air from containment into the HPSI system. The licensee's evaluation did not address this anomaly. However, during the exit meeting, the licensee stated that monitoring of HPSI header pressure during containment pressurization did not indicate any increase in header pressure. On this basis, the licensee did not believe that the ILRT was the source of air in the syste According to log entries, the banging noise that was heard occurred approximately six minutes after HPSI pump 3P-018 was started. This does not support the conclusion that the banging noise was due to check valve sla The evaluation stated that some discrepant pipe supports were identified and concluded that the discrepancies did not occur as a result of this event. The evaluation did not state the basis for this conclusio The Assistant Technical Manager stated that the evaluation would be revised to address the inspector's observation The inspector observed that since Operating Instruction S023-3-required venting of the HPSI system prior to mode 4 entry, there did not appear to be any safety significance to this even This item is closed (50-362/88-20-01). Low Pressure Safety Injection Pump Cavitation During Mid-Loop Draindown (Unit 3)
On July 7, 1988, during reactor coolant system (RCS) draindown to mid-loop conditions, low pressure safety injection (LPSI) pump 3P-015 began cavitating. RCS draindown was being conducted to facilitate pressurizer work and reactor coolant pump (RCP) seal replacement. The control operator stopped the draindown evolution when he noticed fluctuations of approximately 4 amps in pump motor current indication, and 5800 gallons of borated water were added to the RCS to stop cavitation. The refueling water level indicator (RWLI) indicated that RCS water level was at the top of the hot leg (42") when cavitation occurred. Station engineering and operations personnel walked down the RWLI system and did not identify any anomalies. Air was vented from the LPSI system and the operators believed that the air had been introduced during previous maintenance associated with shutdown cooling isolation valve 3HV-9378, and that the air had migrated to the LPSI pump and caused cavitatio After the system was vented, draindown to mid-loop was restarted and LPSI pump cavitation occurred again when RCS level reached the top of the hot leg as indicated by the RWLI. The control operator stopped the draindown evolution and added 3000 gallons of borated water to the RCS to stop LPSI pump cavitation. Following this second cavitation event, instrument and control (I&C) personnel vented the RWLI transmitter reference leg to containment atmosphere and indicated level dropped to approximately 3" below mid-loo Normally, the RWLI transmitter is vented to the pressurizer via permanent system pipin Subsequent investigation by the licensee revealed that the instrument nozzle for the RWLI transmitter vent line had been plugged from inside the pressurizer, causing the RWLI to give
erroneous level indication. The plug was inserted in the nozzle to facilitate installation of a surveillance camera that was used to monitor maintenance activities inside the pressurizer. Actual RCS level at the onset of LPSI pump cavitation was approximately 6" in the hot leg or 15" below mid-loo Corrective Actions As a result of this event, the licensee stated that the following corrective actions would'be taken:
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Operating Instruction S023-3-1.8, which is used to conduct RCS draindown evolutions, will be reviewed to identify and correct any human factors problems. Additional guidance would also be included in the procedure to correlate the gallons drained from the RCS with the expected RWLI indication for the various RCS draindown evolutions normally conducted during a refueling outag As an interim measure, Special Order 88-06, issued on July 8, 1988, required Operations Manager approval to drain the RCS to mid-loop while the above revisions to Operating Instruction S023-3-1.8 were being complete During future RCS draindown evolutions that are conducted with the reactor vessel head installed, the heated junction thermocouples (HJTCs) will be energized to give independent RCS level indicatio This event will be submitted to the human performance evaluation system (HPES) for consideratio A station incident report (SIR) will be initiated to address the root cause and propose corrective actions with regard to the inoperable RWLI sensing lin As a result of the operator's attentiveness and response during this RCS draindown evolution, shutdown cooling (SDC) flow was maintained at greater than 2340 gpm. The Technical Specifications requires a minimum SOC flow of 2200 gpm during mode 6 operatio This item remains open pending review of the licensee's completed SIR (50-362/88-20-02). Reactor Vessel Level Reduction (Unit 3)
On July 25, 1988, with Unit 3 in Mode 5 and preparations being made for engineered safety features (ESF) surveillance testing, operations personnel on day shift noted that pressurizer level was slowly increasing. Over the period of about 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, pressurizer level had increased approximately 20%. When the inspector questioned operations personnel on swing shift about this problem, they were not familiar with the level increase which had been
observed by the previous shifts. The Shift Technical Adviser (STA)
was also not aware of the problem. The STA and operations personnel stated that the anomaly with pressurizer level had.not been included in the shift turnover. The inspector observed that immediate action was taken to pursue this matter and a thorough root cause evaluation was performe The licensee's evaluation concluded that pressurizer level was increasing due to expansion of air trapped in the reactor vessel head. On July 15, following the Cycle IV refueling, the reactor coolant system (RCS) was filled. During this evolution, in accordance with a recently revised procedure, the center control element drive mechanism (CEDM) stack was vented at atmospheric pressure; the other 90 stacks were not. The RCS was then pressurized to 350 psig and pump sweeps were performed, sweeping trapped air from the primary side of the steam generators into the reactor vessel head. Much of this air apparently filled the CEDM stacks; the center stack was again vented, but the remaining 90 stacks were not -- i.e., they were left filled with air compressed to 350 psi Following this fill and vent evolution, the RCS was depressurized and the pressurizer was vented to containment in preparation for the containment integrated leak rate test (CILRT). The licensee concluded that, when the RCS was depressurized, air trapped in the CEDM stacks expanded into the reactor vessel head, depressing the water level in the reactor vesse When the containment cooling units were secured for maintenance and containment temperature began to increase, the air volume in the reactor vessel began to expand and raise pressurizer leve The inspector observed that when the heated junction thermocouples (HJTCs) were energized on July 25, the air volume in the reactor vessel head extended to the top of the RCS hot le The shutdown cooling system was not affected by this event and decay heat removal was not jeopardized. Any additional expansion of the air volume would have been vented to the pressurizer via the RCS hot leg, preventing any further decrease in reactor vessel leve Although there did not appear to be any safety significance associated with this event, it appeared that the licensee's new procedures for venting the RCS should be reconsidered. The licensee committed to review the procedure and make changes as appropriat This item remains open pending review of the licensee's actions to address this concern (50-362/88-20-03).
No violations or deviations were identifie. Monthly Surveillance Activities (61726)
During this report period, the inspectors observed or conducted followup inspection of the following surveillance activities:
a. Observation of Routine Surveillance Activities (Unit 1)
S01-12.31-26 (TCN 1-3)
Auxiliary Feedwater Pump Operability Test (G1O-S)
S01-II-1.1 (TCN 16-4)
Surveillance Requirement -- Reactor Plant Instrumentation Test (Loop A T-Average)
S01-12.1-2 (TCN 3-2)
Reactor Thermal Power Calibration b. Observation of Routine Surveillance Activities (Unit 2)
5023-3-3.24 (TCN 3-2)
Monthly Fuel Handling Building Post Accident Air Cleanup System Test (Attachment 2)
S023-3-3.25 (TCN 7-29)
Once-a-Shift Surveillance (Modes 1 - 4)
c. Observation of Routine Surveillance Activities (Unit 3)
S023-3-3.25 (TCN 7-29)
Once-a-Shift Surveillance (Modes 1 - 4)
S023-3-3.12 (TCN 10-9)
Integrated ESF System Refueling Test No violations or deviations were identifie. Monthly Maintenance Activities (62703)
During this report period, the inspectors observed or conducted follow-up inspection of the following maintenance activities:
a. Observation of Routine Maintenance Activities (Unit 1)
M088070499 Diesel Generator Crankshaft Oil Hole Stress Cracking Nondestructive Examination (NDE)
M088071992 Replace Vital Bus #1 Feeder breaker M088080829 Troubleshooting Main Steam Low Range Radiation Monitor Indicator b. Observation of Routine Maintenance Activities (Units 2 & 3)
M088071209 Replace Saltwater Cooling System Valve 2HCV-6510 (Unit 2)
M087122143 Trip Test Breakers 3D201 and 30203 (Unit 3)
M088012314 Trip Test Breaker 3D206 (Unit 3)
No violations or deviations were identifie.
Engineered Safety Feature Walkdown (71710)
During this inspection period, the inspector walked down the Unit 1 component cooling water system, utilizing system drawings and procedure S01-12.3-31, "CCW System Safety Related Alignment". The inspector performed the walkdown While the Unit was in Modes 4 and The inspector also performed a walkdown of the emergency chilled water system on Unit 3, following completion of the cycle 4 refueling outag In addition to physical verification of valve positions, the inspector reviewed and checked the most recent licensee valve alignment sheets against the P&IDs to confirm that the alignment sheets included all required valve No violations or deviations were identifie.
Independent Inspection (92701)
a. Unit 1 Restart Issues Prior to restart from the second mid-cycle outage, the inspectors verified that the licensee had taken appropriate actions to address the following issues:
Environmental Qualification (EQ) Upgrade and Root Cause Analysis The licensee completed the final EQ review and submitted a letter to the NRC on July 7, 1988, to document the final results of this review. The inspector observed that the identified deficiencies were either repaired or accepted based on engineering review. In the response to the Notice of Violation (50-206/88-10) that was issued to address the EQ deficiencies, the licensee committed to initiate a task force to determine the root cause of this proble The results of this determination are expected to be completed by mid-September, 198 Bunker Ramo Penetrations In a letter dated May 5, 1988, the NRC informed the licensee that the existing Bunker Ramo electrical penetrations did not meet the current EQ requirements. The licensee evaluated the specific application of Bunker Ramo penetrations at San Onofre and determined that these penetrations are only used for control circuits with currents significantly greater than the maximum credible leakage current postulated. The licensee concluded that continued use of the penetrations under these circumstances was acceptabl MOV-1202 Thermal Overload Deficiency A previous inspection report (50-206/88-13, paragraph 9.a) dis cussed the licensee's discovery that thermal overload devices were not installed on auxiliary feedwater valves MOV-1202 and -120 The licensee determined that the thermal overloads on these valves were not bypassed due to a failure to adequately communicate the commitment to the station engineering and maintenance organizations when the MOV was initially installed. The licensee evaluated other MOVs in the plant and found that the thermal overloads were all bypassed as required. As corrective action, the licensee committed to enhance the engineering procedures for modifications to include a line item addressing MOV thermal overloads. This item will be, addressed in the licensee's formal design error root cause evaluation discussed abov Evaluation of the Safety Injection System (SIS)
The licensee conducted a Design Implementation Review (DIR), which was a safety system functional inspection (SSFI) type evaluation of the SIS. The purpose of the DIR was to verify the design basis and assess the operational readiness of the system. Completion of the licensee's study was reported in a letter dated July 25, 1988, and satisfied a commitment established in SCE's letter dated March 17, 1988. No significant deficiencies were identifie Emergency Operating Instructions (EOI) for Single Failure Events In response to the inspector's concern (Inspection Report N /88-16, paragraph 2.e) about using Special Orders to respond to identified single failure events, the licensee revised the EOIs and the Abnormal Alignment Procedures to specify opcratcr action These documents and their revisions were reviewed and approved in accordance with the Technical Specification requirements. The use of Special Orders for specifying operator response was eliminate Diesel Generator Loading (LER 88-09)
While calculating the electrical load for a proposed design change, the licensee found that the maximum load imposed on each emergency diesel generator (DG) could exceed the Technical Specification (TS)
value of 4,725 KW, which was specified for surveillance testin The licensee calculated that the DG loading could be as much as 5,150 KW for DG-1 and 5,020 KW for DG-2. The licensee attributed the cause of these errors to incorrect engineering calculations which left out several safety related motors from the load calculations and used incorrect conversion factors. These errors resulted from poorly controlled engineering review and verification activities. This item was to be addressed in the licensee's formal design error root cause evaluation discussed abov To resolve this problem, the licensee proposed a change to the Technical Specifications to increase the DG load limit to 5,250 K The proposal was approved by NRR subject to the licensee's inspection of selected crankshaft oil holes for stress crackin The inspector observed the licensee's inspection activities and verified that no evidence of cracking was identifie b. Control Room Meter Calibration (Units 1, 2 & 3)
In response to events at other facilities, the inspector reviewed calibration practices at SONGS. These events involved calibration offset problems which resulted when control room meters were installed in orientations different from that for which they were calibrated. The licensee stated that most of the meters in the control room are installed on the vertical boards and calibrated at the test bench, accordingly. Furthermore, the control room indicators are periodically calibrated in place under the existing calibration program. Therefore, it appeared unlikely that a meter would be out of calibration due to installation after bench calibration and go unnoticed for an extended period of time. The inspector was satisfied with the licensee's explanatio Incore Instrument Flexible Conduit Damage (Unit 3)
During inspection of the incore instruments (ICIs) following connector reassembly, the licensee determined that the flexible conduits associated with six of the ICI connectors were torn. The cables inside the conduits did not appear to be damage Nonconformance report (NCR) 3-2008 was issued to address this conditio The cause of conduit damage was attributed to handling difficulties experienced during ICI hookup following reactor vessel head installation during the current refueling outage. The licensee requested that CombustIon Engineering (CE) evaluate the seismic and environmental qualifications of the damaged conduits, and in a letter dated August 5, 1988, CE stated that the qualification status of the damaged conduits was not affected. The inspector observed
- that Appendix R requirements had not been addressed by the NCR dispositio This item remains open pending additional review (50-362/88-20-04).
No violations or deviations in this area were noted during the inspectio.
Review of Licensee Event Reports (90712, 92700)
Through direct observations, discussion with licensee personnel, or review of the records, the following Licensee Event Reports (LERs) were closed:
Unit 1 88-05 Two Fire Protection System Valves Not Included in the Technical Specification Surveillance Program 88-08 Omission of Safety Injection Vent Valves from the Local Leak Rate Test (LLRT) Program
- 88-09 Potential Diesel Generator Loads in Excess of Technical Specification Requirements 88-10 Inadvertent Start of Diesel Generator #2 Unit 2 84-14-01 Fire Protection Program Discrepancies 88-08 CCW System Leakage Exceeds Design Criteria 88-17 Spent Fuel Pool (SFP) Siphon/Failure to Implement UFSAR Commitment Unit 3 84-41 Containment Purge Isolation System (CPIS) Actuation 88-02 Spurious ESF Actuation During Surveillance Testing/Manual Reactor Trip 88-05 Containment Purge Isolation System (CPIS) Train B Actuations on Instrument Failure/Low Gas Count Rate No violations or deviations were identifie. Follow-up of Previously Identified Items (92701)
a. (Open) Follow-up Item (50-362/87-15-01), Calibration Requirements for Flow Instruments This item remained open pending a review of vendor recommendations regarding static alignment of Foxboro flow transmitters. The vendor recommended that the static alignment should be checked as follows:
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At time of initial installation, or
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When the force motor, capsule and/or capsule gaskets have been replaced, or
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If the transmitter does not pass its standard five point up and five point down calibration due to nonlinearities (zero & span adjustment only) or,
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If the flexure locknut has been loosene The vendor did not recommend conducting static alignment verification routinely as a function of the refueling interval instrument calibratio The inspector reviewed Instrument and Test Procedure S0123-II-9.14 (TCN 0-4) and observed that all of the vendor's recommendations were not included. Specifically, the procedure did not require static
alignment verification when the flexure locknut has been loosened, or when the transmitter does not pass its standard calibration due-to nonlinearitie This item remains ope (Closed) Unresolved Item (50-362/88-16-03) Administrative Control of Temporary Pumping Arrangement Used to Transfer Water from the Reactor Vessel Lower Cavity to the Spent Fuel Pool (SFP)
This item involved maintenance personnel rigging of a temporary pump to transfer water from the reactor vessel lower cavity to the SF After the pump was hooked up, a siphon was created by functional testing of the pump which subsequently allowed water to drain out of the SFP. This functional test was performed, with the Control Operator's permission, after installation of the pump. When questioned by the inspector, the Shift Superintendent stated that the evolution was within the scope of established refueling procedures being used by maintenance personne The Refueling Supervisor stated that paragraph 6.3.4 of Maintenance Procedure S023-I-3.1, titled Minor Refueling Procedures, was not properly com plied with when the temporary pump was hooked up and a siphon was create Inspector Follow-up Action The inspector reviewed Maintenance Procedure S023-I-3.1 (TCN 6-12 dated April 28, 1988), and noted that it did not address the transfer of water among the spent fuel pool, reactor cavity, and cask poo It specifically did not provide instructions for trans ferring water directly to the SF The inspector discussed these observations with the Assistant Operations Superintendent for Units 2 and 3 and the Assistant Maintenance Manager, who stated that procedural adequacy had not been evaluated. Following this discussion, the Assistant Maintenance Manager researched this issue further and identified that maintenance order (MO) 87112010 was the appropriate controlling document for transferring water from the lower reactor vessel cavity to the SFP and maintenance personnel should have implemented the requirements of this MO. The inspector reviewed the MO and verified that it was applicable and that instructions were adequate for conducting the water transfer evolutio Conclusions Based on the discussions and reviews discussed above, the inspector made the following observations with regard to this event:
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MO 87112010 was a blanket MO for conducting various water transfer evolutions. Among other provisions, this blanket MO included a precaution to "...
raise.hoses or remove from pool to prevent siphoning when pump is secured."
The Refueling Supervisor and the Assistant Refueling Supervisor failed to 0II
implement this precaution of MO 87112010 when the pump was stopped following the functional test described abov The licensee's initial evaluation and corrective actions to address this issue appeared to be inadequate. In particular, the failure to comply with the MO was not initially understoo As a result, the licensee did not address the failure of maintenance personnel to raise or remove the hose from the fuel pool, and appropriate corrective actions for or actions to prevent recurrence of.this event were not take As discussed in the previous inspection report, SFP level could not have dropped below the Technical Specification required level of 23 feet during this even Criterion V of 10 CFR 50, Appendix B, and the licensee's Topical Quality Assurance Manual require activities affecting quality to be accomplished in accordance with approved instructions or procedure Paragraph 6.13 of Maintenance Procedure 50123-1-1.7, titled Maintenance Order Preparation, Use and Scheduling, requires compliance with work packages and procedure The NRC Enforcement Policy (10 CFR 2, Appendix C, Section VI.G)
states tha the NRC will not normally issue a Notice of Violation-for violations which are identified by the licensee and which meet certain other criteria. One of these criteria is that "It was or will be corrected, including measures to prevent recurrence, within a reasonable time....
". In view of the licensee's failure to implement effective corrective actions after the June 22, 1988 fuel pool siphoning event, the failure to properly implement instructions for transferring water from the reactor vessel lower cavity to the spent fuel pool, as discussed above, is an apparent-violation (50-362/88-20-05). (Closed) Follow-up Item (50-362/88-16-02) Low Pressure Safety Injection Pump Seal Leak During the previous inspection, the inspector observed that nonconformance report.(NCR)-3-2052 did not provide a quantitative safety evaluation of the effect of a degraded shaft seal on low pressure safety injection (LPSI) pump 3P-016. The NCR was revised to provide a more quantitative safety evaluation; however, the inspector observed that the revised safety evaluation focused mainly on seal failure mechanisms and anticipated reactor coolant system (RCS) leak rates and provided very little focus on operational impact and decay heat removal capabilities in the event of seal failur Although 3P-016 was restricted to "emergency use only," the licensee considered the LPSI pump to be operable. While the shaft seal on 3P-016 remained degraded, fuel was loaded back into the reactor vessel and the reactor vessel cavity was drained down to allow installation of the reactor vessel head. In addition, the RCS was
drained to mid-loop to allow reactor coolant pump seal work and pressurizer repair work to be completed. The RCS was at mid-loop for 3 days. With less than 23 feet of water above the fuel, Technical Specification limiting conditions for operation (LCO)
3.4.1.4.2 and 3.9.8.2 required both LPSI pumps to be operable, with one pump operatin After repairs were completed on the pressurizer and reactor coolant pump 3P-004, the RCS was filled and vented and on July 17, 1988, 3P-016 was cleared for seal replacement, and work was completed on July 2 Conclusion Although the licensee's revised safety evaluation was more quantitative, it did not address functional considerations of the shutdown cooling system. In this regard, the inspector made the following observations:
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Technical Specification LCOs specify operability requirements for the LPSI pumps. This LCO and its basis were not addressed in the safety evaluatio The licensee.placed the RCS at mid-loop for a considerable length of time, and industry experience has demonstrated that this condition exposes the RCS to a greater risk of losing shutdown cooling flow. The safety evaluation did not address the consequences of such an even As stated in the previous inspection report, the vendor manual recommends seal replacement if leakage exceeds 50 cc/hr. The revised safety evaluation did not address this vendor recommendation, and vendor concurrence with the licensee's evaluation was not documente The licensee had the opportunity to replace the LPSI pump seal before loading fuel into the reactor vessel, while the shutdown cooling system was not required to be operable. Instead, the licensee chose to replace the degraded LPSI'pump seal at a later date., The Station Manager acknowledged the inspector's comments at the exit meeting, and stated that the decision was made to delay repair work.on 3P-016 until the RCS loops were returned to service and available for decay heat remova This item is close (Closed) Followup Item (50-362/87-05-01) Acceptability of Agastat Relay Tolerances The inspector previously identified that several Agastat relay timers did not function within the required time interval during integrated ESF testing. The licensee evaluated this condition and concluded that in certain instances the design tolerances for Agastat relay response time would allow the Agastat relay to function slightly outside of the Technical Specification required
time interva The licensee currently readjusts Agastat relays that do not function within the Technical Specification required time interval, and action was being taken to identify an acceptable replacement relay for these applications. Based on discussions with NRR, the inspector determined that the licensee's actions were appropriate. This item is close.
Follow-up on NRC Bulletin (92701)
As requested by action item e. of Bulletin 85-03, "Motor-Operated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings," the licensee identified the selected safety-related valves, the valves' maximum differential pressures, and the licensee's program to assure valve operability in the letter dated May 19, 198 Review of this response indicated the need for additional information which was contained in Region V letter dated June 30, 198 NRR review of the licensee's August 21, 1987 response to this request for additional information indicated that the licensee's selection of the applicable safety-related valves to be addressed and the valves' maximum differential pressures met the requirements of the Bulletin. The licensee's program to assure valve operability was found to be acceptable. Other aspects of the licensee's program will continue to be tracked as Unresolved Item 86-34-0 No violations or deviations were identifie.
12. Unresolved Item An unresolved item is a matter about which the NRC requires additional information in order to determine whether the matter is a violation, a deviation, or an acceptable item. An unresolved item is discussed in paragraph.
Exit Meeting (30703)
On August 16, 1988, an exit meeting was conducted with the licensee representatives identified in Paragraph 1. The inspectors summarized the inspection scope and findings as described in the Results section of this repor The licensee acknowledged the inspection findings and noted that appropriate corrective actions would be implemented where warranted. The licensee did not identify as proprietary any of the information provided to or reviewed by the inspectors during this inspection.