IR 05000206/1986037
| ML13323B215 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 10/28/1986 |
| From: | Huey F, Johnson P, Stewart J, Tang R, Tatum J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13323B214 | List: |
| References | |
| 50-206-86-37, 50-361-86-27, 50-362-86-25, NUDOCS 8611180366 | |
| Download: ML13323B215 (21) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report No /86-37, 50-361/86-27, 50-362/86-25 Docket No.50-206, 50-361, 50-362 License No DPR-13NPF-10, NFE-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:. August 16 through October 8, 1986 Inspectors:
F. R.. Huey, Senior Resident Date Si ned Inspector, Units 1, 2 and 3 J. P. Stewart, Resident Inspector Date S gned J. E. Tatum, Resident I spector Date S gned R. C. Tang, Resident Inspector Date Signed Approved By:
P. H. Johnson,-Chief Date S gned Reactor Projects Section 3 Inspection Summary Inspection on August 16 through October 8,- 1986 (Repo6rt No /86-37, 50-361/86-27; 50-362/86-25)
Areas Inspected: Routine resident inspection of Units 1, 2 and 3 Operation Program including the following areas:
bperational safety verification,.
evaluation of plant trips and events, monthly surveillance activities'rmonthly maintenance activities, independent inspection, licensee event report review,
-and follow-up of previously identified items. Inspection procedures 30703,.
37910, 61726, 62700, 62703, 71707, 71710, 73051, 92701 and 93702 were covere Results:
No violations or deviations were identifie PDR ADOCK 05000206
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DETAILS Persons Contacted Southern California Edison Company H. Ray, Vice President., Site Manager
- G. Morgan, Station Manager M. Wharton, Deputy Station Manager D. Schone, Quality Assurance Manager D. Stonecipher, Quality Control Manager R., Krieger, Operations Manager D. Shull, Maintenaice Manager J. Reilly, Technical. Manager P. Knapp, Health Physics Manager
- B. Zint1, Compliance Manager
- D. Peacor, Emergency Preparedness Manager P. Eller, Security Manager W. Marsh, Operations.Superintendent, Units 2/3 J. Reeder, Operations Superintendent, Unit 1 V. Fisher, Assistant Operatiods Superintendent, Units 2/3 B. Joyce, Maintenance Manager, Units 2/3 H..Merten, Maintenance Manager, Unit 1 T. Mackey, Compliance Supervisor
- C,. Couser, Compliance Engineer San Diego Gas & Electric Company
- R. Erickson, San Diego Gas and Electric
- Denotes those attending the exit meeting on October 10, 1986.
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.
Operational Safety Veflfiction
- 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 housekeepirig, examination for potential -fire hazards, fluid leaks, excessive vibration, and verification that naintenance requests had been initiated for equipment in need of maintenanc Housekeeping During. this inspection period the inspector observed that housekeeping had improved from previous periods..One weakness that was observed, however, involved evidence of cigarettes in non
smoking areas. Two cigarette butts were found in a class 1E cable tray, and an appreciable number of cigarette butts were seen in other areas of the plant that are designated as non-smoking. The inspector emphasized this weakness at the exit interview. The licensee addressed current efforts to resolve this problem. The inspector will monitor progress during future inspection Unit 2 Reactor Startup Following the September 13 spurious trip of Unit 2, the inspector observed the licensee post trip review effort and subsequent reactor plant startup conducted onSeptember 14, 1986. The inspector noted the following deficiencies, which were reviewed with the plant operations manager:
(1) The shift' technical advisor (STAY did not properly document the corrective actions implemented to preclude recurrence of the trip. These actions,are required to be documented in section 2.4.2'of attachment 4 of procedure 50123-0-25 (post trip review).
This omission was not corrected by the shift superintendent during his review of the for It'should-be noted that the licensee had taken proper corrective actions and although the missing data from the post trip review form were of minor actual significance, it demonstrated a lack of rigorous implementation of corrective actions 'reviously identified'by the licensee (e.g., following the'Apfil 13, 1986 early criticality event on Unit 3, the licensee identified the need to ensure more rigorous documentation of all post trip review.actions).
The licensee' agreed and stated that all cognizant operations personnel have been recounseled on the importance of proper documentation of all post trip review action ) Step 2.5.2 of procedure S0123-0-25 provided no acceptance criteria for' determining proper operation of the reactor trip breakers. 'The licensee agreed that the addition of this-criteria would improve the procedure and committed to revise it accordingl (3) Step 3.4.8.1 of procedure S023-3-1.1 (reactor startup) require that the teactor operator confirm expected reactivity addition-by ensuring thatsource range couit rate increases' in direct proportion to the positive reactivity inserted during withdrawal of shutdown and part length' control rod group During the September 14 startup, the -reactor operator verified this step, although source'range count rate had less'than doubled during a control rod withdrawal sequence that should have reduced reactor shutdown margin by a factor of three (e.g., source range-count rate should have tripled).
Review of this concern with the shift superintendent identified that although he recognized that count rate did not respond in direct proportion to shutdown group reactivity additions (due to excore detector geometry and core self shielding effects),
he considered that the intent of the procedure-was to ensure
proper source range instrument response more from a qualitative than quantitative standpoiht..During discussion of this item
- with the inspector the plant operations manager agreed that the importance of reactor startup.and the difficulties experienced during the April 13th event, warrant additional procedure clarity with regard to the criteria for.-monitoring proper plant response. The licensee committed to. revise this procedure accordingl (4) Plant operators were not fulfilling the intent of step 3.4.7 of procedure SO23-3 -l.l, which requires use of an inverse count rate plot (i/M plot) for confirming proper plant response during approach to criticality evolutions. Followingthe April 13 early criticality event on Unit 3, licensee corrective actions included implementation of the requirement to perform a 1/Mplot for all reactor startup During the reactor plant startup on September -14th, plant operators performed a 1/M plot, however, noneof.thedhold point estimated critical position (ECP projections fell within the allowable ECP band-(all projections fellbeyond the all rods out (ARO) upper fimit indicating the need for primary boron dilution). A review of this 'concern with the STA and cognizant technical supervisor identified that similar situations -have developed during previous reactor startups and in each case the shift superintendent selected the option in the procedure to continue rod-withdrawal past the hold point even though ECP-projections fell outside the allowable 1/M.plot band. The inspector reviewed his ~coheern with-the plant operations manager that such an approach to use of a 1/M plot defeats the primary purpose for performing a 1/M plo If all-hold points-result in ECP projections outside of the allowable band, th reactivity addition interval between hold points-should be reduced to provide a meaningful ECP projection. The licensee agreed and committed to revise the procedure and retrain cognizant personnel accordingly.'
No-violations or deviations were identifie.
Evaluation of-Plant Trips and Events Reactor Trip on September 4, 1986 (Unit 3)
-The reactor tripped-from 90% power on September 4, 1986, when the turbine trip solenoid valves were deenergized -causing a turbine tri The reactor subsequently -tripped due to loss of load. An equipment operator was closing DC breaker 3D507 to connect non lE bus 3B5 to,the spare charger and, as the breaker closed, the operator.inadvertently tripped DC'breaker 3D506 which-was supplying power to the.turbine control system. The operator was not using the proper tooltooperate the breaker, and evidently his hand slipped off when the breaker--snapped into position. The licensee instructed the operators to use the proper tools when operating breakers. The unit was returned to power operation on. September 6, 198 Feedwater Pump Failure on September 4, 1986 (Unit 1)
At 2142 on September 4, 1986 with reactor power at 52%, the West Main Feedwater Pump (MFP) low lube oil pressure alarm come in. and operators immediately inspectedthe pump and declared the pump inoperable -at -214 The MFP also serves as a safety injection pump and a reactor shutdown was initialed at 2235 as required by the plant Technicqa Specifications. An Unusual Event was declared at this time -in accordance with the Emergency Pla Licensee Event Report 86-011 describes the cause of the MFP shaft-failure and corrective action.,Unit 1 remained out of-service until 1507 on October 1, 1986, to repair the West MFP and other equipment deficiencies identified while performing maintenance activities during the outag Reactor Trip on September 13, 1986 (Unit 2)
At 0952 on September 13, 1986, Unit 2 tripped from 60% power due to a spurious position indication signal from Control Element-Assembly (CEA) 3 This occurred when, during movement of part length CEA group 1, anerratic position indication signal from CEA 34 to Control.Element Assembly Calculator. (CEAC) 1 caused generation of penalty factors.to the Core Protection Calculator (CPC) Departure fromNucleate.Boiling Ratio (DNBR) and Local Power Density (LPD)
calculations,. resulting in the generation of a reactor trip signal by all four CPC The Reed Switch Position Transmitter for CEA 34 was found to be defective and was replaced. The unit was returned to full power at 0215 on September 15, 198 The above reactor trip occurred when the reactor protection system conservatively applies-the penalty factors from a single CEAC'to all CPC channels even though both CEACs were in servic The-licensee'
is currently working with the vendor, Combustion Engineering, in developing'means to prevent single train CEAC output to the CPCs from causing reactor trip Unit Shutdown On September 30, 1986 (Unit 3)
At 0201 on September 30, 1986,' the unit was removed from service to replace the reactor coolant pump (RCP) seals. The seals had been degrading on pumps 1 and 3, and the controlled bleed off flow was exceeding 3.5 gpm with a controlled bleed off' temperature approaching 1700F.. ;The inspector observed that the reactor shutdown was well controlled and occurred without incident. The licensee.
plans to install Bingham-Willamette seals in an effort to resolve the problem of repetitive failures of the original seals. These-,
seals have already been installed on the Unit 2 RCPs and appear to be working wel The unit was scheduled to return to service on October 22' 1986.'
5 Shutdown to Repair Oil: Leak on the est Main Feedwater Pump on October 2, 1986 (Unit 1 On October 1, 1986, a low lubeoil pressurealarm was received on the West MFP. The licensee: immediately inspected the pump and noted excessive oil coming out of the West MFP motor eniclosur Th licensee, after conducting a preliminary investigation, commenced a shutdown of Unit 1 to perform a-detailed inspection of the MF The cause of the oil leak was determined to be improper assembly of the inboard bearing of the MFP motor. The Unit returned to operation at 2335 on October 3, 1986., Accumulation of Sea Shells in Main Condenser (Unit. 1)
Power was reduced on several occasions for cleaning of sea shells from the saltwater side of the iMain condenser., Power was-reduced to as low as 20% during the period from August 27 to August 31, 1986 and 64% from September 2 to September 4, 198.
Monthly Surveillance Activities Unit 1 The inspector observed the following surveillance:
S01-V-2.1 Quarterly Auxiliary Feedwater Inservice Pump Test (Dedicated Shutdown Pump) Unit 2 The inspector observed portions of the following surveillances:
31 day -surveillance for Reactor Plant Protection System (RPPS)
Channel B Channel-Function Test (CFT) (Procedure S023-II-1.1.2, TCN 0-10).
31 day CFT for RPPS Channel C (Procedure -S023-II-1.1.2, TCN 0-6).
31 day surveillance on turbine plant area sump radiation monitor (2RT-7821) (Procedures S023-II-9.17, TCN 4-2, SO-23--XXV-4.42, TCN 0-2).
18 month calibration of control room airborne particulate/iodine monitor Channel A (2/3 RT-7825 A2) (Procedure S023-II-4..37, TCN 3-9).
31 day surveillance on Control Room Emergency Air Cleanup System Train B (CREACUS)
(Procedure S023-3-3.20, ;TCN 7-3).
92 day surveillance on plant vent stack/waste gas holdup tank radiation monitor (2/3 RT 7808A, B C) (Procedure S023-XXV-4.18 TCN 0-2).
- 6 Electrical test portion of the 31 day" reactor plant protection system matrix trip path testingj(Procedure'SO23-I-1,.1.5, Rev 0,At t 2).
31-day surveillance (functional test for control room isolation train B) *on control room airborne gas monitor (2/3 RT.7825)
(Procedure S023-II-4.9, TCN 8-7)_
18 month calibration of 2PT-6462 (at outlet ping of CC critical loop A heat exchanger) (Procedures S0/23-I-I-8.10.,1, TCN 0-7; S023-II-9.13, Rev 6, TCN 6-6). Unit 3 The inspector observed-the 31 day channel functional test of the excore.nuclear instruments, safety channel This surveillance i required by Section 4.3.1.1 of the Technical Specificat ions, and was conducted in accordance with procedure SO23-II-The inspector observed the 31 day reactor plantprotection system logic matrix functional tes The inspector observed the conduct of this surveillance on several separate occasions, and found that it was well controlled and the procedure was being closely adhered t This surveillance is required by paragraph 4.3.2.1 of the Technical Specifications, and is conducted in accordance with procedure S023-II-1. All of the above surveillances were observed to be performed in accordance with current plant procedures, and no abnormalities were noted
'No violations or deviations were identifie. Monthly Maintenance Activities est Feedwater Pump/Safety Injection Pump Shaft Failure (Unit 1)
The inspector observed :part of thereipair efforts on the Unit-1 West Feedwater Pump. The pump was inoperable as a result of the pump shaft failure on September 3, 198 Similar problems occurred in May 1985 and June 1986. The pump shaft fractured at the thread engagement section where the oil pump drive nut is threaded onto the shaft. The licensee's investigation 'of the failure concluded that the primary failure mode was most likely due to the loss of preload force on the nut, followed by thread to thread fretting between the shaft and the nut., The fretting caused a large free play clearance to be generated for the thrust.disk, thereby resulting in a high cyclic force on the nut end fac The licensee revised the maintenance procedure for installing the oil pump drive nut on the shaft to ensure that the proper preload force is applie The licensee also implemented.corrective actions for other identified potential causes of the failure During discussion of this problem with the inspectors, the licensee agreed that more extensive troubleshooting and root cause evaluation in May 1985 and June 1986
could have identified the pump failure mechanism earlier. The licensee has imjlemented a more aggressive program for determining root caus West Feedwater Pump/Safety InJection Pump Motor Bearing Oil Leakage (Unit 1)
The inspector observed part of the repair efforts on the Unit 1 West Feedwater Pump Motor, bearings.' The pump was taken out of service on October 2., 1986 due to"excessiv oil 'leaking from the inboard motor-bearin Upon disassembly of the motor 'bearing', it was determined that the bearing labyrinth seals had been reassembled improperly. The reassembly error prevented the oil, which normally accumulates in the labyrinth' seal from being directed back to the'
top. of the journal'bearin The licensee identified the following weaknesses in the maintenance program which contributed to the reassembly error: (1) an inadequate maintenance procedure which did not properly address labyrinth seal vent "'and.(2) failure to properly identify -and control component parts -upon disassembly of equipment components. The licensee revised the procedure 301-1-5.68, 'to clearly identify. the requirement to ensure that the vent holes are on 'the top half of the labyrinth seal The failure to properly -identify and control component parts appears to have been an isolated ccurrence, and the inspectors will monitor this item during future maintenance activitie Switchyard Breaket/Disconnects (Unit.1)
The inspector observed maintenance troubleshooting on the open pole alarm on the.off-site power supply breaker and disconnects to the'
Unit 1 C Transformer. The troubleshooting identified no.degradation of the disconnects and it was determined that the alarm occurred primarily as a result of the low power placed on the two supply breakers 4032 and 603 Post Accident Sampling System (PASS) (Unit 2)
The boron meter and the pH analyzer in the Unit 2/3 PASS were noted to be out" of calibration during a chemistry surveillance in July, 1986. The.inspector observed the licensee recalibrate the PH analyzer (2/3 AI-A503). "The calibration was successfully completed in accordance with procedures S023-II-9.681, Rev.O, TCN 0-1, and S023-II-9..383, Rev 1. During observation of calibration of boron meter (2/3 AI-A502), the inspector noticed-that the.I&C technicians performing the above calibration did not appear to be familiar with the procedure (which was recently revised to incorporate steps for using a new.sample cart)., Section 6.8 of this procedure (Restoration and Return to Service) requires the petformance of "a functional test per the design 'documents."
The technicians indicated that they did not understand what'this meant and that functional tests should be performedby operations. The I&C technicians indicated that it was the first time they had used this procedure and that no briefing'was conducted by the I&C supervisor prior' to. starting the activity. The inspector reviewed this problem
with the I&C supervisor and was informed that a pre-job briefing should have been conducted to discuss the work scope,'to go over any new procedures, etc..This problem.was also reviewed with the maintenance manager, who committed to reemphasize the importance of proper pre-work briefing with cognizant personne With regard to the functional test requirement of the procedure, the I&C'supervisor stated that this was a boiler plate statement which had been inserted in the procedure and that a post-maintenance functional test of the PASS is adtually intended to be performed by the Chemistry Department. The inspector stressed that technicians should not be left.to make a decision as to which steps can be skipped. The licensee later issued a TCN to delete this statement froin the procedur Inlet Drain Valve for Spent Fuel Pool Heat Exchanger E005 (Unit 2)
The,inspector examined the valve on September 2nd after a replacement disc assembly had been installed. The inspector also reviewed the maintenance documentation package and discussed the activity with the maintenance and QC personnel. No deviations or violations were identifie While the maintenance activity was in progress, a maintenance worker outside the spent fuel pool heat exchanger room noticed that a frisker outside the Unit 2 penetration building "jail house" (20 feet away) went.off scale and the associated audible alarm sounde Health Physics was notified and an'air sample.was taken inside the
"jail house 10 minutes late In exiting the Health Physics
.,control point, both the inspector and the three maintenance workers discovered contamination on their hands and faces due to noble gases.. -The collected air sample was.analyzed to contain approximately 23 time's MPC of noble gases, principally Xe-133. The resultant skin dose to an individual present-in that vicinity was estimated to be 0.6 mrad/hr. The Health Physics foreman immediately placed' a rope and sign outside,the Unit 2 penetration building, declaring it an airborne area. The puff release of noble gases was later determined to be due toaleakage:through 2HV0511 (pressurizer apor sample containment isolation valve) during the valve alignment portion.of the reactor water inventory balance which is conducted three times a.week by operations. A packing leak in 2HV0511 was repaired within two days,' prior to the next'scheduled -surveillanc Air samples were taken in the "jail house" after the valve repair and indicated 0% MPC of I-131 and noble gase in addition, Health Physics and Operations Departments have reached an agreement on the prioritization.of.Red Badge Zone Valve and systems leak The inspector considered the above corrective actions taken by the licensee" to be adequat Gas Sampling System The gas sampling system blower suction pressure relief/safety valve (2/3 PSV 0579) had been.observed to leak by, causing-the waste gas header flow alarm to annunciate and.gas releases out the vent stac A maintenance order was generated to adjust the lift: setppint of the valve.' The inspector observed portions of the bench test on the valve and reviewed the completed maintenance packag The valve lift setpoint-wasfound t6 be-accep table. The setpoint as engraved on the valve name plate was 50 psi. However, it had previously been changed to-60 psi per DCP 5023-507 (5/25/84) as. indicated in the-maintenance order but was never changed on the nameplate. The maintenance technician engraved the new lift setpointon the nameplate. The entire bench test was observed by a QC inspecto Component Cooling Water (CCW) Heat Exchanger Pressure Switch Repair (Unit 3)
The saltwater differential pressure (d/p) alarm switch, 3 PDSHL-6533, for the CCW heat exchanger, E-002, was continuously in the alarm condition even wheh the saltwater d/p indication was satisfactory. The licensee removed the switch and-found that the tubing had become clogged to the point where the pressure switch could not functio The licensee cleaned the tubing and the pressure pressureeswitch, and installed the switch back into the system. The inspector observed switch installation and reviewed the work procedure..The inspector observed that the I&C technician.was using a screwdriver to tighten a star nut inside the pressure switch, and brought this to the licensee's attention. The licensee inspected thepressure switch to ensure that no damage occurred, and emphasized the proper use of tools-to the technician Steam Generator Safety ave plaement Unit 3)
During the RCP Seal Outage, the licensee replaced safety valves 3PSV-8407, 8408 and 8409. These three valves were all installed on the same steam header, and were exhibiting excessive vibration during unit operation. The inspector observed -the valve replacement and reviewed the work procedure., The evolution was well controlled and conducted in 'accordance with the procedures. The licensee plans to-verify the valve lift setting when the unit enters mode Qualified Safety Parameters Dispiay System (QSPDS) (Unit 3)
QSPDS Channel A has had a problem with the plasma display unit (PDU)
since original-installation. The PDU will display, spurious characters such that the display of safety'patameters degrades over tim While this is'
expected to occur to some extent,.the problem has been significantly worse on Channel A for Unit'3 than on any of the other PDUs. The inspector has monitoredthe licensee"s efforts to identify and correct this problem,which has Included replacing the PDU, replacing the key pad, grounding the unit-at a different location and monitoring.radio frequenc RF) noisein te area. The problem was significantly reduced when a sittr t
connector cable was used, which indicates that the cable has been actin as an antenna and picking up RF noise. The licensee has not determined why the condition is worse for QSPDS Channel A on Unit 3 tha ait is for Channel B or for either.of the channels on Unit 2., but the shorter cable has helpedt resolve the roble No violations or deviations were identified Engineered Safety Featu e Walkdown During the inspection period, the inspector walked dow, major portions of the:safety injection system for Unit The system as observed was aligned as required by the unit Technical Specifications and" aplicable station procedure One of the rooms which houses HPSI pump 2P-017 and LPSI pump 2P-015 (Room 005) had a health physics lock on the door because of hot.spots present at several piping elbows (up to 10 r/hr on contact).
A person seeking access to the room would need to obtain a key from Health Physic The inspector questioned whether an operator's accessibility to the room during.emergencies would be affected (delayed)
by the lock, and whether use of shielding around the hot spots had been considered. The.lock was later removed, since licensee procedures only require Health Physics locks for areas with radiation levels of greater than. 15 r/hr. The icensec is currently developing a plah to build permanent shielding around the piping elbow No violations or deviations were identifie.
Independent Inspection Evaluation of Root Cause Assessments Made by the Licensee The inspectors reviewed several component failures that have recently occurred to,assess the licensee' s program for determining the root cause of component failure In particular, the inspectors selected the following examples:
(1) Faulty Potter and Brumfield Relay (Unit 2)
As discussed in paragraph 3b of inspection report 50-361/86-24, the licensee attributed the cause of the Unit 2 reactor trip on July 14, 1986, to the pitted contacts of a Potter and Brumfield relay #KR3D However, it is questionable that the minor pitting that existed on the contacts would have caused the relay to fail, and the licensee did not test the relay to confirm the postulated failure mechanism. The troubleshooting and repair effort was conducted under a Shift Superintendent's Accelerated Maintenance (SSAM) work request, which did not provide guidance fr conducting the troubleshooting and repair effor The SSAM did not address root cause identification of the relay failure, ahd the mechanical relay was not preserved in the "as found" conditionso that subsequent testing could be performed. In addition to the procedural inadequacies, the non conformance report (NCR) which addressed the mechanical relay failure'was not issued-until after the troubleshooting and repair.effort was completed. The NCR, in this instance, did not provide for QA overview and in-process control of the failed componen (2) Spurious Tripping of 2HV-4730 Supply Breaker (Unit 2)
aOn September 4, 1986, breaker MS-4705, which supplies power to valve 2HV-4730,-spuriously tripped ope This valve is a DC powered motor operated valve,(MOV) which is located in the
'auxiliary feedwater (AFW)-piping to steam generator E-088. The licensee initiated a maintenance order to replace the breaker, and a replacement breaker was installed on September 11, 198 The licensee could not identify a cause for the breaker to trip, andafter performing the necessary valve surveillance, returned the valve to operable status. On September 27, 1986, breaker MS-4705 spuriously tripped open again. The licensee initiated a maitenance order and did extensiVe troubleshooting to identify the cause of the proble *This effort. included high pot testing of the electrical circuitry associated with the breaker and a-search for any electrical noise in the area
.that might cause the breaker to tri The licensee has not been able.to identify a cause for.the spurious breaker tripping, but speculates that it is due to vibration of the electrical panel which houses the breaker. The licensee has instrumented the breaker so that if it trips again, a determination can-be made as to the cause-of the tri Although the inspector considers that.the actions taken by the licensee for the September 27th occurrence were satisfactory, similar actions should have been taken by the licensee for the September 4th occurrence. Adequate testing was not done to determine root cause, and measures were not taken at that time to enable a root cause determination in the event of subsequent spurious breaker trip ) Failure -of. Valve 3HV-4706 to Open (Unit 3)
Following the reactor trip that occurred on September 4, 1986, anEmergency Feedwater Actuation Signal (EFAS) was generated.
due to the low steam generator (S/G),water levels that resulted. Valve 3HV-4706, the steam driven auxiliary feedwater (AFW) pump discharge valve for S/G E-089, failed to open. The licensee issued a maintenance order to investigate the cause of failure. The valve'was cycled several times, the limit switch compartment was inspected, the motor windings were meggered, the power feeder cables were meggered-and the valve,running current was measured. An explanation for the valve failure was not found,,and the licensee declared the-valve operable at 0140 on September-5, 1-98 Unit 3 was rettirhed to service on September 5, 1986. Following the reactor start-up, the licensee revised the original maintenance drder to provide instructions to replace the breaker for valve 3HV4706. The maintenance order was not worked until September 9, 198 On September 8, the inspectors expressed concern that troubleshodting performed on September 5 had not been adequate to determine the cause, of valve malfunctio On September 9, the licensee initiated additional troubleshooting. of the breaker for valve 31{'4706 and found that the supply breaker for valve, 3V-4706 was not properly set to give adequate margin between the valve motor full load curk&nt and the breaker
instantaneous trip current setting. The licensee determined that the breaker was improperly set during original installation, and is currently.assessing corrective actions to identify any other breakers'that may be set incorrectl The inspector expressed concern that the shift superintendent's accelerated maintenance (SSAM) process may have.contributed to 1inadequate root cause assessments. In particular, th inspector noted:'that many'equipment malfunctions which require a careful and disciplined root.cause assessment are likely to occur under conditions which warrant use of the SSAM proces The inspector noted' that the use of a SSAM may contributed t the problems involving the Potter and Brumfield relay, valve 2HV4730 and valve 3HV4706, as discussed above. The specific aspects' of the SSAM process which appear to warrant additional consideration fall into two categories:
(a)' The criteria for using a SSAM rather than-a normal, maintenance order (MO)
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The use of a SSAM did not appear to be warranted in the instance of.relay troubleshooting, since the plant.was already in Mode (b) The specific guidance provided by the SSAM procedure Incorporation of additional guidance in the basic SSAM procedure with regard to root '6ause evaluation and preservation of "as found." conditions may provIide 'greater assurance of proper evaluation and correction of future equipment malfunction The 'inspectors-are concerned that these above examples may
'indicate that additional licensee attention is needed in the area of root cause assessment. Furthermore, it appeats that the Quality Assurance (QA).organization may need to take a more aggressive role in the area'of root cause evaluatio The. inspectors will review the licensee's assessment of corrective actions to.identify other breakers that may have incorrect trip setting In addition, the adequacy of the SSAM process to determine component failure root cause and the'
.-extent of-QA involvement in this 'process will be further evaluated as open item (50-362/86-25-01). IST on AFW Pump, The inspector observed the In Service Test (IST)'of the Unit 2 Steam Driven.Auxiliaty Feedwater Pump (2P-140) which is performed monthly as required by the Technical Specifications 4.7.1.2.1. All'measured parameters were within the acceptable ranges and the pump did not exhibit any abnormal performance trend CRIS Radiation Monitors'
On September 20, 1986, while Train B.of the Control Room Isolation Systems (CRIS).radiation monitors (2RT-7825) was under routine
surveillance, the CRIS TrainA monitor (2RT-7824) had essentially no flow through it.. The operator manually.initiated CRIS and 2RT-7825 was subsequently returned to service after the surveillance. The fan belt of the blower for 2RT-7824 had broken -
possibly due to warm temperature in the room which made the belt brittle and eventually broke. The licensee performs preventive maintenance on these-fan belts every 92 days and the next scheduled-maintenance.was on September 30, 198 Technical Specifications (T.S. 3/4.3.2., 3/4.3.3) require that control room emergency air clean up system be initiated and maintained in the isolation mode within one hour when both Trains of CRIS are out of. service. Control room annunciators associated with these monitors are:
CRIS TR A Hi-Radiation/Trouble, and CRIS TR B Hi Radiation/Trouble. -Theoperator, in response, must go to the hallway outside the control room to identify the failed monitor (i.e.,.gas or iodine/particulateY and return to the control room to determine what actions to take. As indicated in the corresponding alarm response procedure, causes of, these two alarms include channel failure, loss of power to CRIS, and high radiation level in the control room complex..."Channel failure" is intended to mean failure in the monitor and/or in any portion of the circuit.downstream of, i Low flow or no flow to a monitor, as in the case mentioned above, would not have caused this alarm to flas Instead, an amber light out-in the hallway would have been lighted, according to some operators, the status of these radiation monitors is checked once per shif If loss of flow.to the-monitors occurs after the shiftly surveillance, it would be unnoticed unless and until someone goes out to the hallway. By the same token, if the light bulb burns out, a low f low condition would also remain-unknown,to the operator. The inspector noted that in the'event of real emergency, (high radiation level in the control room complex) the "Control.room area radiation monitor high radiation" alarm would annunciat The inspector was informed by the licensee project engineer that 'a DCP had been generated to provide-direct indication in the control room.of the status of individual radiation monitors. Im1plementation of the DCP will be completed -in the next few months and will resolve the above concern. The implementation of adequate compensatory measutes to ensure proper response to radiation monitor failures, pending completion of the.DCP, temains an open item (50-361/86-27-01). Resin Transfer, Spent resin sluiries are normally dewatered to §0.5% free standing
',water prior to packaging, shipping and ultimate disposal.' The inspector observed the -licensee perform the water-separator relative humidity end point determination. No violations or deviations were note e Replacement -Operator Training Region.V was.requested by Mr. William R. Russell, Director, Division of Human Factors Technology, NRR, to conduct an inspection to determine if the licensee has been conducting replacement operator
training according to the requirements of 10'CFR 55 and NUREG 073 Emphasis for this, inspection was to be on 'in plant practical factors, three months on shift training, and retention of record This inspection was conducted in office with' appropriate records supplied,by facility personne (1) Completion 'of Practical Factors In discussions with plant training personnel, and based on examination of representative records, it was determined that the last class of.license candidates that Region V examined had completed' the required training' as outlined in the facility's replacement training program. The implementation of the INPO accredited program however, had not been completed at the time these individuals had commenced.their training. Therefore the facility had these individuals complete their training for INPO accreditation certificates after they had completed the training required under the replacement training program.. This meant that some individuals did-not complete'this aspect of their training program until after they had received their licenses. The review determined that those items that had not been completed were not required for meeting the NRC requirements for. licensing.(1OCFR'55 and NUREG 0737).
(2) Retention of Records The facility is committed per FSAR Chapter 13.2 to Regulatory Guide 1.8 Rev. 1. "Personnel Selection and Training". This Reg. Guide endorses ANSI 18.1 -
1971Property "ANSI code" (as page type) with input value "ANSI 18.1 -</br></br>1971" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. Rev. '1 "Selection and Training of Nuclear Power Plant Personnel".
Section 5.6 of-the ANSI standard says: "Records of the qualifications, experience, training and retraining of each member of the plant organization should be maintained."
The replacement training program of January.22, 1986, referenced in the Revision 1 to'. the FSAR Chapter 13.2, does not define specific record' retention requirements in this area. In conversations with the facility.training personnel they stated that they did retain in permanent plant records a memorandum to
'file from the Unit Superintendent attesting that the individual had completed all of'the required in plant praictical'factor The personnel also'stated that they did retain all records of in plant practical' factors. The personnel-also stated that they did retain all records of in plant practical factors training until the individual license candidate is license (3) On Shift vs. Simulator Training The facility has not in the past equired that' their license candidates conduct reactivity manipulations on the plant. The facility does however require that all reactivity manipulations be'performed on the plant specific simulator. The iicense candidates that.have gone up for.licensing in the past have also performed at least 5 manipulations on the plan Region V
Opetator Licensing personnel have inf6rmed the facility that this. is a requirement, to istablish that the individual license candidate has been trained to operate the actual controls of the plant. The training personnel have indicated that-they will have their license candidates perform the 5 manipulations requirement on the plan Environmental Qualification (EQ) of Auxiliary (AFW)
Valves (Units.2/3)
When conducting follow-up inspection associated with AFW containment isolation valve 2HV-4730,. the inspector noted that the valve is not included in the licensee's EQ program. This.appeared'to be inconsistent with the requirements of IOCFR50.49 because this valve, along with the other three AFW containment penetration isolation valves associated with both trains of AF, is located in a small concrete 'structure (doghouse) which also houses parts of the steam generator (S/G) blowdown system for both S/G The blowdown system components which are located in the doghouse include the containment penetrations and associated isolation valves, downstream check valves, a welded pipe restraint and associated piping.. The.AFW valves located in the doghouse are HV-4714, HV-'4715, HV-4730 and HV-4731. These valves are for containment isolation purposes and are normally closed, but are required to open upon receipt of an emergency feedwater actuation signal (EFAS).
The AFW valves and the blowdown'valves located in the doghouse are not included in the licensee's EQ progra This configuration i essentially the same for both Units 2 and 3. The inspector addressed this issue' with the licensee, arid the following points were discussed:
(1) Pipe Break Scenario -
The licensee stated that a break in' in the blowdown piping is not.postulated as stated in the FSAR, paragraph 3.6A.3.4.2, and allowed by Branch Technical Position MEB 3-1 dated 197 (2) Blowdown System Component Failure - The licensee stated that if the blowdownpiping did actually break in the doghouse area, the effect 'on S/G water levels would be minor, a reactor trip would not occur, and a need for auxiliary feedwater would not exis This scenario would encompass any possible component failur (3)
Inservice Irspection (IST) Requirements - The licensee stated that the blowdownpiping from the penetrations to the blowdown penetration isolation valves is ASME Section III Class 2 piping; and is inspected as required by ASME Section XI. There is no ISI performed on the ANSI B3 1.1 piping and welded restraining welds located-downstream of the'blowdown isolation valve The inspector has reviewed the FSAR, and the following aspects of this issue remain in question:
(1).-The design requirements for the ANSI B31.1 sections of blowdown pipingare not addressed in the FSAR, and paragraph 3.6.2.1.2.2.D states:
"Pipe breaks arenot postulated in piping between containment isolation valves (up to and including the.pipe whip restraints that define the terminal ends for the run)...."
Evidently the 'licensee is using some other criteria such that a pipe break is not postulated at the welded pipe restrain (2). The pipe restraints, which are welded to the blowdown piping, are designed such that the welds areaccessible for 100%
volumetric examination as required by the 'FSAR, paragraph 3.6.2.1.2.2.D.2.f, but the licensee currently does not perform ISI on these weld (3) Paragraph 3.6A.3.5.2.4 addresses EQ regarding the AFW valves inside the AFW pump roo EQ is required for the postulated event of a break in the steim line to the AFW pump turbin This event does not seem to be any more severe than a break in the blowdown piping inside the dogho'use, and it does not appear to be consitent to exclude the AF valves located inside the doghouse frdm7 the EQ requirement A break in the blowdown piping or component failure (such as a failed packing gland or failure of a gasketed joint) within the doghousefarea has the potential of affecting both trains of AFW, and could compromise the safe shutdown capability of the reacto This issue, applicable.to Units 2 and 3, is unresolved pending disposition by NRR 50-3 1/86-27-02). Reactor Plant Protection System (RPPS) Degraded Power Supply (Unit 2)
As discussed in paragraph 3.b of inspection report 50-361/86-24, a reactor.trip occurred while conducting MSIS matrix testing. During this report period, additional anomalies occurred related to the Unit 2 RPPS. On September 3, 1986,.a CIAS-was received on one of the four trip paths.' Later,' the' I&C technicians observed that an indicating light associated with one of the EFAS trip paths was exhibiting a fluctuating intensity. The licensee initially traced the problem to two separate solid state relay cards, one for EFAS and one for.CIAS. The'relay cards were replaced,' and the problems appeared to.be resolved.,owever, in examining 'all of these anomalies together,. the licensee identified a power supply that was common to the MSIS, CIAS and EFAS problems that had been experienced. The.power supply-was tested using a strip chart recorder and an AC ripple was found in the DC outpu Evidently, this condition was not severe enough to-be detected by a digital voltmeter (DVM) and'was not identified during the initia troubleshooting efforts. The licensee now believes that the degrading power supply actually caused the solid state relay cards to malfunction. The degraded power supply was replaced and the other power supplies associated with the RPPS were checked to ensure
proper operatio Similar RPPS anomalies have recurred since the power supply was replace Loss of Main Steam/Main Feedwater Flow Mismatch Trip Function on July 30, 1986 (Unit 1)
On July 30, 1986, a pressure transmitter (PT-459) in.the density compensation circuit of the steam flow instrument,failed,: resulting in the failure 6f-all three steam/feedwater flow mismatch trips in the reactor protective system (RPS).- As a result of the 'failure o all three channels of a technical specification required RPS function, the licensee initiated a plant shutdown in accordance with the requirements of technical specification 3.0.3,.
Prior to completing the plant-shutdown, the licensee completed repair of the pressure transmitter; exited the technical specification action statement and returned the plant to power operatio Prior to exiting the action statement,.the inspectors questioned the licensee regarding the basis for continued plant operation with a RIPS trip function that is subject to single component failure. At, that time,,the licensee responded that the steam/f eedwater flw mismatch' trip was not believed to be taken credit for in the safety analysis and plant protection in the event of loss of-feedwater accidents was provided 'by high pressurizer level tri Subsequent to return of the plant to power operation, on October 2, the licensee completed a-review which concluded that (1) the trip function of steam/feel flow.mismatch) trip wabtakned credit for in the loss of feed/feedwater rupture analysis 'perfo rmed followifng'the TiL accident; and (2) the reactor trip function.ofhigh pressurizer level at 70% would have tripped the plant, if the steam/feed floi trip.circuit were inoperable, however, the resultant transient was outside the scope of the plant design analysis (e.g. itwas determined that the pressurizef would go solid and cause the primary safety valves to,lift and pass water-instead of steam)
As a result, the liceq'see took' prompt action to implement compensatory measures to eliminate dependency on the steam/.feedwater flow mismatch trip and maintain 'the plant within its existing design analysis (e.g. the' licensee reduced.the setpoint of the high pressurizer level'trip from 70% to 50% pressurizer level).
During subsequent' review of this problem with licensee management, the inspector again expressed concern regarding the decision to return the plant to power operation prior to clearly establishing the basis for operation with a.RPS function that is subject to single component failure. The licensee stated that the decision to
.return the plant to power operation was properly based on the repair of the defective instrument and did not require resolution of the question of. RPS single failure criterion. The licensee did agree, however, that the basis for continued operation should have been clearly established and documented in a more timely fashion. This issue remains open pending further review (50-206/86-37-01).
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18 Review of Licensee Event Reports 86-19 (Unit 2):
This LER was issued to discuss the circumstances surrounding the reactor trip that occurred on July 14, 1986. This event was previously discussed in paragraph 3b of inspection-report 50-361/86-24 and is further discussed in paragraph 7 of.this report. The LER is misleading. A hypothesis was developed based on the fact that a mechanical relay failed to initially rese However, the relay did reset when the I & C technicians were trying to gain access to it. In addition, when the relay was bench tested (before the-slightly pitted contacts were burnished),,there was no indication of degraded relay performance. The facts being as they are, the actual cause of the relay failure is not well understood. A hypothesis for the reactor trip was presented in th LER, but it was stated as factual instead of hypothetical. The inspector has reviewed this LER with the licensee, and the importance of accurate information was emphasized. This point was also stressed at' the exit meetin Through direct observations, discussions with licensee personnel, or review of the records, the following Licensee Event Reports (LERs) were closed:
Unit 1 86-001 Missed surveillance of diesel generator yalves86-003 Missed plant vent stack filter sample 86-004 Inoperable charging pump 86-006 Missed plant vent stack sample 86-007 Auxiliary feed actuation and steam PT failure 86-008 Reactor trip due to governor,' valve 'losure Unit 2 86-006 Dose Equivalent Iodine Limits Exceeded 86-008 Source Range Neutron Monitor Malfunction 86-009 AFW Pump Steam Supply Check Valve War 86-010 FHIS Train tB+/- Actuation 86-011 CPIS Spurious Actuation 86-012 PPS.Actuation on Low Reactor Coolant Flow 86-014 125 Volt DC Battery Surveillance 86-015 Unit 2 Trip Due to Failure of IE Inverter 86-017 Pacific Scientific PSA-100 Failures Unit 3 86-002
- Missed CPC Channel Functional Test 86-003
'Pressurizer Instrument Nozzle Leak
.86-004 Unanalyzed Purge Sample 86-005 Reactor Trip Non lE' Instrument Bus.Transient 86-006 Unit 3 Trip During Reactor Startup 86-007 Missed TurbineBuilding Sump Effluent Sample
86-008 CPIS Actuation 86-009 AFW Pump Steam Supply.Check Valve Damage 86-010 Reactor Trip on Loss of Feedwater 86-011 Saltwater Cooling Loops Inoperable Follow-Up of Previously Identified Items Allegation RV-86-A-010 (1)
.Characterization The alleger, a contract maintenance worker, reported that workers can be-fired for raising personnel safety concern The alleger stat ed that a Urit 1 foreman stated this to the allege (2)
Implied Safety Significance to Operation This item would be of major safety significance, if the allegation is substantiate (3) Assessment of Safety Significance Based upon interviews with twelve contract (Fluot)maintenance personnel, the inspector determined the following:
(a) Eleven personnel stated that weekly safety meetings are held as part of the licensee's emphasis on personnel safetylpractice (b)The average on siteeiperience for the twelve workers was eight year )
HaIf the workers interviewed rated the Industrial Safety Practices as exc'ellent and half rated them as goo Several workers stated that the San Onofre plant was the most safety oriented facility at which they, had ever vworked in l
the latten to twenty year (d)
All' twelve workers persorially knew who the Fluor Personnel Safety Representative was. All twelve felt that they would 'not be-fired f'or 'rais'ing industrial safety concern V, Eleven of the twelve workers felt that they would never be asked to work in an,unsafe condition because of the safety practices which exist at San Onofr (e)
One of the twelve workers had raised a safety concern on, one occasion. He believed that his concern was satisfactorily resolved and he does not feel that he would be fired over raising safety concern (4) Staff Position
The allegation that workers can be-fired for raising safety concerns was not substantiate (5) Actiot Required Based on the inspector's findings, the allegations were not substantiate The resident inspectors, as part of observation of maintenance activities on site, will routinely obserre safety,,practices and question workers on the safety practice *This allegation is close.
Exit Meeting On October 10, 1986, an exit meeting was conducted with the licensee representatives identified in'Paragraph 1. The inspectors'summarized the inspection scope and findings as described in this report.