IR 05000275/1988032
| ML16341F009 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/10/1989 |
| From: | Johnston K, Mendonca M, Narbut P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F007 | List: |
| References | |
| 50-275-88-32, 50-323-88-30, NUDOCS 8902280385 | |
| Download: ML16341F009 (40) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION REGION V
Report Nos:
50-275/88-32 and 50-323/88-30 Docket Nos:
50-275 and 50-323 License Nos:
Pacific Gas and Electric Company 77 Beale Street, Room 1451 San Fr anci sco, California 94106 Facility Name:
Inspection at:
Diablo Canyon Units 1 and
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
December 4, 1988 through January 21,1989
~ ~i
~ ~~~ CY~
c. ~ /~
K.
E. Johnston, Resident Inspector
~~~c~ g P.
P.
Narbut, Senior Resident Inspector Approved by:
w/~~gyp Date Signed
@+i'm p Date Signed
~/i~gz p M.
M. Mendonca, Chief, Reactor ProjectsSection I Date Signed Summary:
Ins ection from December 4'988 throu h Januar
1989 Re ort Nos.
50-275/88-32 and 50-323/88-30)
Areas Ins ected:
The inspection included routine inspections of plant
~ operations, maintenance and surveillance activities, follow-up of onsite events, open items, and licensee event reports (LERs),
as well as selected independent inspection activities.
Inspection Procedures 30702, 30703, 37702,'0500, 61726, 62703, 71707, 71710, 90712, 92701, and 93702 were used as guidance during this inspection.
Results of Ins ection:
No violations or deviations were identified.
Areas of. Stren th During the reporting period, the licensee produced two commendable documents:
o As described in paragraph 4. e. the licensee issued a procedure to perform checks of sealed valves every six months versus every refueling outage in order to heighten their awareness and assurance of sealed valve positions.
BS'02280385 890214 PDR ADQCK 05000275 PNU
o As. described in paragraph 4.o.
the maintenance organization performed a maintenance history analysis and issued a nonconformance report as a vehicle to comprehensively address recurring problems with feedwater regulating valves.
The maintenance organization has taken this approach in other problem areas (such as steam dump valves) in order to categorize the problem areas and attack the problem in a coordinated manner.
Areas of Weakness During the reporting period weakness were noted as follows:
o Additional operational errors were noted as has been the case in the previous two resident inspection reports.
This report describes a
liquid radwaste discharge performed with an inoperable radiation monitor due to operator error (paragraph 4. i), an inoperable auxiliary feedwater pump due to a valve lineup error (paragraph 4. 1),
a missed surveillance on control rod position due to operations oversight (paragraph 4.m),
and a mode transition made with an inoperable reactor cavity flow indicator due to operator oversight (paragraph 4.a).
The matter of operational errors and increasing NRC concern was the subject of a meeting held at the site with plant management and the Deputy Regional Administrator on January 26, 1989.
o In technically complex areas, backshift operating personnel failed to seek advice from management and engineering prior to taking actions which subsequently required analysis to justify the actions.
Specifically, an experiment affecting boron concentrations in the pressurizer was conducted (paragraph 4. n. ) and ventilation modifications to vital battery rooms were made (paragraph 4. k) by backshift operating personnel without consultation.
o Examples of inadequate post maintenance testing were identified.
Specifically, post maintenance tests performed were not adequate to identify a wiring error on a reactor cavity flow meter (paragraph 4.a)
nor to identify a valve lineup error on an auxiliary feedwater pump (paragraph 4. 1).
o The long-standing issue (raised in the licensee's SALP report for the period ending June 30, 1988) of a lack of thorough and timely analysis and resolution of problem areas is evident in two areas of the inspection report.
Specifically, the licensee is issuing a
greater number of event reports which do not address root cause and corrective actions but defer to a commitment to provide a
supplemental report at an undefined future date.
This appears to be a negative quality trend as described in paragraph 9.c.
Additionally, the issue of valve lineup and equipment configuration problems identified in the last two resident inspector reports and this one, does not appear to have sparked comprehensive licensee analysis or corrective action.
Action taken through the end of the reporting period has been limited to writing a nonconformance report and the consideration of actions as described in paragraph 4. DETAILS 1.
Persons Contacted PG8E Attendees:
J.
D. Townsend, Plant Manager
- D. B. Miklush, Assistant Plant Manager, Maintenance Services L.
F.
Womack, Assistant Plant Manager, Operations Services
+"B. Giffin, Assistant Plant Manager, Technical Services J.
M. Gisclon, Assistant Plant Manager for Support Services
- C.
L. Eldridge, equality Control Manager T. Bennett, Maintenance Manager D.,'A. Taggert, Director guality Support
"T. J. Martin, Training Manager W.
G. Crockett, Instrumentation and Control Maintenance Manager J.
V. Boots, Chemistry and Radiation Protection Manager T.
L. Grebel, Regulatory Compliance Supervisor
"S.
R. Fridley, Operations Manager R.
P.
Powers, Radiation Protection Manager
+M.
R. Tresler, Project Engineer S.
M. Skidmore, guality Assurance Manager
"W. J. Kelly, Regulatory Compliance Engineer
"R.
L. Watson, guality Support Engineer
"W. T.
Rapp, Onsite Review Group Chairman
+E.
R. Kahler, Engineering Support Services
+M. J.
Jacobsen, Engineering Support Services
+T.
G. deUriarte, Supervising Engineer, Nuclear Regulatory Affairs
+J.
W. Blakley, Senior Engineer, Nuclear Regulatory Affairs
"Denotes those attending the exit interview on January 13, 1989.
+Denotes PG8E attendees at the Configuration Management Program meeting held December 9,
1988, at the Region V Office in Walnut Creek, California.
The inspectors interviewed several other licensee employees including shift foremen (SFM), reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, quality assur ance personnel and general construction/startup personnel.
NRC Attendees at December
1988 Confi uration Mana ement Meetin
D.
F. Kirsch, Director, Division of Reactor Safety 8 Projects, Region V
M.
M. Mendonca, Chief, Project Section 1,
DRS&P, Region V
H.
Rood, Diablo Canyon Project Manager, NRR A.
D. Toth, Engineering Inspector, Region V
J.
P. O'Brian, Project Inspector, Region V
K.
E. Johnston, Diablo Canyon Inspector
2.
0 erational Status of Diablo Can on Units 1 and
Unit 1 was at power throughout the reporting period.
Unit 2 began the reporting period in Mode 3 in preparation for startup from its second refueling outage.
The outage was declared complete on December 8,
1988.
The unit continued power ascension testing and remained at power for the remainder of the reporting period.
This was the licensee's first return to power from a refueling outage without a reactor trip.
3.
0 erational Safet Verification 71707)
a.
General During the inspection period, the inspectors observed and examined activities to verify the operational safety of the licensee's facility.
The observations and examinations of those activities were conducted on a daily, weekly or monthly basis.
On a daily basis, the inspectors observed control room activities to verify compliance with selected Limiting Conditions for Operations (LCOs) as prescribed in the facility Technical Specifications (TS).
Logs, instrumentation, recorder traces, and other operational records were examined to obtain information on plant conditions, and trends were reviewed for compliance with regulatory requirements.
Shift turnovers were observed on a sample basis to verify that all pertinent information of plant status was relayed.
During each week, the inspectors toured the accessible areas of the facility to observe the following:
(a)
General plant and equipment conditions.
(b)
Fire hazards and fire fighting equipment.
(c)
Radiation protection controls.
(d)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures.
(e)
Interiors of electrical and control panels.
(f)
Implementation of selected portions of the licensee's physical security plan.
(g)
Plant housekeeping and cleanliness.
'h)
Engineered safety feature equipment alignment and conditions.
(i)
Storage of pressurized gas bottles.
The inspectors talked with operators in the control room, and other plant personnel.
The discussions centered on pertinent topics of
general plant conditions, procedures, security, training, and other aspects of the involved work activities.
En ineered Safet Feature Walkdown 71710 During the report period the inspector examined the diesel fuel oil storage and transfer system including the transfer pump vaults, the diesel generator day tanks and filters.
On the diesel generator itself the fuel oil system, lube oil system, air system, cooling system, and local controls were observed.
The inspector had certain observations regarding a proposed modification to the diesel fuel oil transfer system.
The modification, based on probabilistic risk assessment studies, changes the operating logic of the transfer pumps from as needed service to continuous run service.
The inspector's questions regarding possible transfer pump vault filter clogging and ambient temperature buildup were identified to the system engineer and were given to the NRC inspection team (commencing a safety system functional inspection (SSFI)
on the diesel system on January 23, 1989).
No violations or deviations were identified.
4.
Onsite Event Follow-u 93702 Mode Transitions Performed with Ino erable Technical S ecification EcCEui ment On December 3, 1988, the Unit 2 Shift Foreman noted that the reactor cavity flow transmitter and totalizer were not operable and had not been since September 26, 1988.
The discovery was made upon processing a work order to repair the items.
The problem had been noted on September 26 and an Action Request written at the time with the Unit in Mode 6 (refueling),
however a technical specification equipment status sheet was not filled out at that time.
The technical specification equipment status sheet is the licensee's administrative method of controlling equipment required by technical specifications.
The reactor cavity flow monitoring system is required by technical specifications to be operable in Modes 1 through 4 per technical speci ficat ion 3. 4. 6. l.
Technical specification 3.0.4 prohibits mode transitions unless the limiting condition for operation is satisfied without reliance on the applicable action statements.
The licensee entered Mode 4 on November 27 and Mode 3 on November 29, 1988.
The licensee prepared a nonconformance report (NCR DC-2"88-WP-N142)
and LER 2-88-021.
The licensee's investigative action to date indicates:
o in the properly calibrated state the sump flow monitoring system is sluggish to respond, the discharge flow indicates lower flow than expected for a few minutes as the discharge line volume is filled.
o a separate wiring error was made on September 30 in a design change to add test circuitry.
This error was not detected by post modification testing.
The sump flow indicator was corrected and tested satisfactorily on the day of discovery:
December 3,
1988.
The licensee's LER states that the-corrective actions to prevent recurrence are not developed and will be addressed in an LER supplement.
The inspectors will follow the licensee's action through the LER process.
b.
Unit 2 Post Outa e Criticalit On December 6, 1988, Unit 2 achieved criticality after its second refueling outage.
On December 8, 1988, the outage was declared completed when the unit was closed on the electrical grid and commenced power output.
c.
Power Ran e Instrument Miscalibrated On December 8,
1988, nuclear instrument N-42 was declared inoperable due to having been calibrated to an outdated calibration requirement.
The miscalibration was noted as the unit reached 20K power and the one channel was noted to read 4X lower than the other three power range channels.
The miscalibrated channel was recalibrated and returned to service on December 8,
1988.
The licensee prepared a nonconformance report NCR DC2-88-TT-N143.
The inspectors will follow-up the licensee's corrective action through the NCR process.
Justification for Continued 0 eration for a Sus ect Molded Case Circuit Breaker On December 9, 1988, the licensee prepared and approved a
justification for continued operation (JCO) for a molded case circuit breaker as required by NRC Bulletin 88-10 "Nonconforming Molded Case Circuit Breakers."
The particular breaker is used to supply power to safety related battery charger No.
231.
The inspector reviewed the JCO and found it acceptable.
Revision to the Sealed Valve Verification Fre uenc On December 15, 1988, the licensee issued a revised procedure (@PC-9Sl) to increase the performance of verification of sealed
va)ves from once every refueling to once every eighteen months.
The change was made in response to the inspector's findings and concerns regarding seal valve problems.
Safet In ection Flow Balancin Found Im ro erl Set On December 15, 1988, the licensee discovered that the safety injection flow balance 'test for Unit 2, which had been performed in 1985, had left the system in a flow balance condition that did not meet technical specification requirements for safety injection by 7.5 gallons per minute.
The technical specifications require 463 gpm and actual was 455.5 gpm for the recorded total of the three lowest cold leg readings.
The problem apparently arose from the unexpected loosening of locking nuts for valves that assure flow balance.
The licensee had Mestinghouse perform a safety analysis which concluded the lower flow did not invalidate ECCS analysis and did not compromise safety.
The licensee prepared an submitted LER 2-85-30.
Corrective action specified in the LER appears adequate and the LER is considered cl osed.
Unit 2 Power Reduction due to Vibration On December 20, 1988, the inspector became aware of significant vibrations in the Unit 2 turbine building in the area of the heater drain pump.
The heater drain pump is not safety related but provides a substantial amount of feedwater from the main steam reheaters to the feed water pump suction.
The vibration was noticeable enough to cause shaking of deck plates and steel structures.
The area had been posted with personnel warnings by the shift foreman.
The licensee had not observed the vibration during power ascension but licensee management took prompt action to evaluate the situation through vibration analysis.
The vibration analysis indicated that the heater drain pump was providing the driving frequency through the system fluid vice directly through piping.
Vibration levels on the pump itself were low but vibration of the suction piping was high and visually noticeable.
The suction pipe vibration was transmitted directly to turbine building structural steel by a rigid pipe hanger arrangement.
Licensee management implemented an investigative plan which included a reduction in heater drain flow, reduction in power, turning off the pump, and radiographing the pump suction valve.
The pump suction valve was the only item in the system worked during the refueling outage and stem/disk separation was postulated.
The radiographs showed a satisfactory stem disk connectio None of the flow and power reductions changed the vibration level.
When the pump was turned off the vibration ceased.
The pump was then disassembled and inspection revealed a metallic object in the pump suction.
The object was determined to be part of a lapping tool used in the outage work performed on the suction valve.
The object was disk shaped about 3 inches in,diameter and about 1/0 inch thick and apparently caused flow perturbations inducing suction piping vibration.
The maintenance manager stated the outage work on the suction valve was performed by general construction (contractor) forces but was performed with foreign material exclusion controls and with gC inspection.
He further stated that the controls were obviou'sly not sufficient and that corrective action would be generated through root cause analysis.
A balance-of-plant quality evaluation report (BOP-gE)
was generated to ensure a root cause analysis is performed.
The pump was returned to service on December 23, 1988.
Vibration levels were acceptable.
Entr into Technical S ecification 3.0.3 On December 21, 1986, and again on December 23, 1988, the licensee entered technical specification 3.0.3 when both trains of the Auxiliary Building Ventilation System shutdown.
The December 21 event occurred during testing of modified fan inlet vane controllers.
The licensee has been conducting a thorough examination and the causes appear to be related to a combination of mai ntenance and design considerations.
The licensee prepared an LER 2-88-22.
The LER states that a
supplemental LER will be submitted when cause and corrective actions are fully determined.
The inspectors will follow-up licensee action through the LER revision to be submitted.
Li uid Radwaste Dischar e with an Ino erable Radiation Monitor On December 26, 1988, operators in Unit 1 performed a liquid radwaste discharge with the applicable radiation monitor (RM-18)
The cause of the event was the failure of an operator to return the radiation monitor to service after testing it in preparation for the discharge.
Liquid samples before and after the discharge confirmed that no improper radiological conditions occurred.
The licensee prepared and issued LER 1-88-31.
The inspector reviewed the licensee's actions and determined them to be adequate.
LER 1-88-31 is close Excessive Oil Absorbant Pads Increase Fire Hazard On December 28, 1988, the inspector discussed an observation with the Assistant Plant Manager for Operations.
Specifically, plant personnel were using excessive absorbant pads under operating equipment such as the charging pumps.
The inspectors concern was that the chances of a fire hazard were greater with wick-like materi'al should an arc or spark occur.
The operations manager and the fire protection management concurred and committed to minimize the use of absorbant pads.
Vital Batter Low Tem eratures On December 29, 1988, Unit 2 vital battery bank 2-1 was declared inoperable due to ambient room temperatures and the batteries dropping to below the technical specification limit of 60 degrees F.
The condition existed for just over 45 minutes.
The room and batteries were warmed by allowing warm turbine building air to circulate through opened fire doors which had been appropriately posted with fire watches.
The licensee prepared and issued LER 2-88-23 on the event.
The proposed corrective actions appear appropriate.
The LER is considered closed.
It should be noted that prior to the event, the night shift foreman for operations had noted dropping temperatures and had the ventilation supply ducts taped over.
The inspector noted this action to be inappropriate since neither management nor engineering personnel were consulted nor were appropriate controls such as the jumper log utilized.
Licensee management concurred with the inspectors assessment and included corrective actions in the LER.
This is an example of an inappropriate effective design change made by operating personnel without proper engineering evaluation or concurrence.
Ino erable Auxiliar Feedwater Pum On December 31, 1988, the licensee discovered during a planned monthly surveillance test of the Unit 2 steam driven Auxiliary Feedwater pump, that the pump had been inoperable for a period of time.
The period of time could not be positively determined and was considered no longer than the previous successful monthly operational test done on November 30, 1988.
When the December 31, 1988, test was performed the room filled with steam due to a test connection valve being open instead of closed and its corresponding test line uncapped'nstead of capped as required for operation.
The licensee prepared and issued an LER 2-88-024 which concludes that the pump would have failed because of high room temperature The LER 'did not reach a definitive conclusion regarding root cause nor definitive corrective actions to prevent recurrence.
The LER states that a supplemental LER will be issued.
The resident inspectors and regional management conferred with licensee management regarding this apparent valve lineup discrepancy and others.
The licensee consequently performed additional investigations to attempt to determine the cause of the misaligned valve.
The results of the licensee investigation were not definitive and are reflected in the LER.
The occurrence of this valve lineup error is another example of a continuing problem with the, accurate conduct of valve lineups.
This issue has been addressed in the previous two resident inspection reports (50-275/88-31 and 50-275/88-26).
Licensee management has thus fat responded by recognizing the problem, issuing a nonconformance report (NCR-DCO-89-N003 issued January 9, 1989),
and has reviewed the problem, considered actions and continues to consider actions that might be taken.
The matter of the inoperable auxiliary feedwater pump 2-1 is considered unresolved pending future examination of the occurrence (Unresolved Item 50-323/88-30-01).
Control Rod Position Surveillance not Performed On December 31, 1988, operators in Unit 2 failed to perform a four hour surveillance verifying rod positions.
The surveillance was required by technical specifications because the rod insertion limit monitor had been declared inoperable on August 27, 1988, and four hour surveillances were required since that time.
Although the problem had been identified prior to and corrected during the Unit 2 outage, post maintenance testing which was performed during startup had not been signed off as complete.
The monitor was in service and would have performed its alarm function but had not been declared operable and therefore survei llances were administratively still required.
The missed surveillance was caused by an operations department administrative error in that a form used to record the four hour surveillance was not set out at midnight December 31, 1988.
Consequently, the surveillance was missed at 0100 December 31 and every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> thereafter until 0900 on January 1, 1989, when the missed surveillance was noted and recommenced.
The inspector will follow-up licensee corrective actions through the nonconformance written on the matter (DC2-89-0P-N004).
Decisions Ina ro riate for Backshift Personnel On January 5, 1989, the inspector noted that the Unit 2 shift foreman had conducted an experiment on backshift.
Although not
prohibited by technical specifications, and by subsequent analysis the experiment was not unsafe, nonetheless the inspector was concerned that the shift foreman was not sufficiently cautious in seeking engineering and management concurrence to his actions.
Specifically, the shift foreman reduced the number of pressurizer heaters in service from the normal number used in Diablo's operation to date (backup heaters were turned off and only proportional heaters were used).
As expected, spray flow automatically reduced, maintaining adequate pressure control.
The shift foreman was also correct in predicting that boron concentration in the pressurizer would increase because Diablo was running with continuous off gas sampling from the pressurizer gas space.
This eventually caused a difference in boron concentration in the pressurizer of about +300 ppm versus the reactor coolant system boron concentration.
Westinghouse operational guidelines recommend a difference of no greater than 50 ppm.
The licensee subsequently stated that their analysis showed that increased boron concentration in the pressurizer was not a safety concern but could lead to operational problems in a loss of pressure situation causing a power reduction due to the injection of the more highly, boron concentrated pressurizer fluid.
This matter was discussed with licensee management as an additional example of insufficient caution on the part of operating personnel, and a lack of proper interface between operating personnel, management and engineering.
o.
Positive Maintenance Action on Feedwater Re ulator Valves On January 10, 1989, licensee management issued nonconformance report DCO-89-TI-N001 on recurring stroke time failure of feedwater regulating valves.
This action was commendable in that the licensee maintenance personnel did a history search of recurring problems with these valves, categorized the problems and plans to deal with the problems in a comprehensive fashion.
The inspectors will follow-up the licensee's actions through the nonconformance.
violations or deviations were identified.
The inspectors observed portions of, and reviewed records on, selected maintenance activities to assure compliance with approved procedures, technical specifications, and appropriate industry codes and standards.
Furthermore, the inspectors verified maintenance activities were performed by qualified personnel, in accordance with fire protection and
housekeeping controls, and replacement parts were appropriately certified.
During the reporting period, the inspectors examined maintenance related aspects as described in paragraph 4 of this report.
Specifically, maintenance of the reactor cavity flow transmitter, calibration of nuclear instruments, heater drain pump maintenance, auxiliary building ventilation modification, maintenance housekeeping, auxiliary feedwater pump preventative maintenance, and feedwater regulating valve maintenance were examined as described in paragraphs 4. a, 4. c, 4. g, 4. h, 4. j, 4. 1 and 4.o, respectively.
In addition, the maintenance activity described below was examined.
Diesel Generator Maintenance The inspector observed portions of routine diesel generator maintenance.
Specifically, the inspector observed preventative maintenance performed on the radiator fan drive including lubrication and inspection.
The mechanic performed the work in accordance with work order R0042617.
The inspector noted that the work order was deficient in that the instructions given were.not specific.
As an example oil level was specified "fill as required" and fan blade capscrews were specified as
"check for tightness".
The work order did not provide a specific oil level nor a specific torque value.
The mechanic performing the work stated that he had filled the oil to an apparently correct oil plug level and had checked the capscrews snug tight.
He stated that he was going to check with his foreman for further instructions to ensure his actions were proper.
His foreman had the diesel generator technical manual.
The inspector discussed the matter with the assistant plant manager for Maintenance, the work planning manager, and the maintenance manager.
Licensee management agreed that the work order was not specific enough and stated that the standing instructions to maintenance mechanics and work planners had not been carried through as intended.
They stated that they would reemphasize the intent to provide specific information to the planner and mechanics and understood that the adequacy of work orders would be examined in the future.
No violations or deviations were identified.
Surveillance 61726 By direct observation and record review of selected surveillance testing, the inspectors assured compliance with TS requirements and plant procedures.
The inspectors verified that test equipment was calibrated, and acceptance criteria were met or appropriately dispositioned.
During the reporting period the inspectors examined surveillance testing activities as described in paragraph 4.
Specifically, surveillance
testing, aspects of the reactor cavity flow indicator, molded case circuit breaker testing, safety injection flow balance testing, radiation monitor functional testing, battery testing, auxiliary feedwater pump testing, and rod position surveillance testing as described in paragraphs 4a, 4d, 4f, 4i, 4k, 41, and 4m respectively were examined.
In addition, on January 6, 1989, the inspector observed, the diesel fuel oil transfer pump preventative maintenance and surveillance testing.
No violations or deviations were identified.
Radiol o ical Protection 71707 The inspectors periodically observed radiological protection practices to determi ne whether the licensee's program was being implemented in conformance with facility policies and p'rocedures and in compliance with regulatory requirements.
The inspectors verified that health physics supervisors and professionals conducted frequent plant tours to observe activities in progress and were generally aware of significant plant activities, particularly those related to radiological conditions and/or challenges.
ALARA consideration was found to be an integral part of each RWP (Radiation Work Permit).
Plant Dischar e In uir On December 19, 1988, the resident inspector received a request from the Headquarters Duty Officer to examine plant radiation discharges over the preceding weekend.
The request was in response to a member of the public who noted increased readings on a radiation monitoring device.
The inspector checked plant vent, air ejector discharge and steam generator blowdown tank radiation monitor printouts for the weekend and found them to have read at normal background readings for the weekend.
Inquiries to plant staff and log review showed that no containment vent or gas decay tank discharge occurred over the weekend.
Wind directions for the weekend showed abnormal wind directions.
Specifically, due to storms the weekend winds were predominantly from landward and south as opposed to normal seaward and northwest, which may account for the differences noted.
No violations or deviations were identified.
Ph s ica 1 Securi t 71707 Secur ity activities were observed for conformance with regulatory requirements, implementation of the site security plan, and administrative procedures including vehicle and personnel access screening, personnel badging, site security force manning, compensatory measures, and protected and vital area integrity.
Exterior lighting was checked during backshift inspections.
Proper compensatory actions and personnel logging were verified as required.
No violations or deviations were identifie.
Licensee Event Re ort Follow-u (92700)
a.
Status of LERs The LERs identified below were closed out after review and selected follow-up inspections were performed by the inspectors to verify licensee corrective.actions:
Unit 1:
88-27, 88-11 Revision 1, 88-3.5 Revision 1, 88-30, 88-18, 88-25, and 88-31 Unit 2:
88-18, 88-19, 88-30, 88-13, and 88-23 Additionally, special report SR-88-10 on Unit 2 low temperature overpressure protection actuations was reviewed and closed.
b.
0 en LER 2-88-020-00 Containment Ventilation, Isolation and Fuel Handlin Bui ldin Ventilation Shift to the Iodine Removal Mode due to an Electrical Transient The licensee submitted the LER on December 23, 1988, describing the event of November 28, 1988, which was caused by a momentary loss of vital 120v AC power to one of the vital power distribution panels (PY-22).
The inspector's review of the subject LER resulted in comments for the licensee, specifically:
o Comment:
The LER, in describing components affected by the voltage transient, described those components using site nomenclature rather than descriptive language.
Specifically, the LER described actuations of "FCV-128", "RM-28A", and
"FCV-111A" rather than the charging pump discharge flow control valve, plant vent particulate radiation monitor and primary water flow control to the boric acid blender, respectively.
o Comment:
The LER makes conclusionary statements without providing the rationale or source of information for those conclusionary statements.
Some of the conclusionary statements border on being suppositional statements and require further explanation.
For instance,. the statement that the loss of voltage was "only milliseconds in duration" was not based on a measurement or record but was a subjective judgement based on operators experience with annunciators that flashed and went out before
.signals sealed in.
For instance, the solid state protection system (SSPS)
monitor light for main steam isolation came in during the event, its seal in time is 40 milliseconds.
The main steam isolation valves did not go shut because they are physically closed by venting air off an actuator and the signal to the solenoid vent valve does not seal in.
Therefore, the solenoid valve may have been powered for a short time but insufficient to'ent significant ai Li.kewise, the LER stated that an overheated lug "had developed over a long period of time" and
"was not a contributory factor to the event".
Further discussion with the licensee indicated that his conclusion was a judgement by an electrical maintenance engineer based on disassembly and inspection of the lug and lack of melt/remelt surfaces.
In response to the inspector's comments on the LER, the licensee committed to submit an LER revision.
Inspection follow-up will be performed in review of the LER revision.
LERs with Incom lete Root Cause and Corrective Action The inspectors had noted a disturbing trend for LERs (which must be provided within 30 days of discovery of a reportable event) to be submitted with incomplete root cause and/or corrective actions to prevent recurrence.
Additionally, the LER's do not provide a
commitment as to when a supplemental LER can be expected.
This condition is especially disturbing in light of discussion (of PG8;E's tendency to lack timeliness in addressing problems and their resolutions) that was held in the Systematic Assessment of Licensee Performance (SALP) meeting on October 27, 1988.
Examples noted during this report period included:
o LER-1-88-26 dealing with a September 1, 1988, reactor trip due to a valved out anti-motoring relay.
The LER states corrective action is under investigation and does not commit to a supplement or date of resolution.
o LER-1-88-25, dealing with a reactor trip on August 30, 1988, due to a main feed pump trip, states corrective action is to be provided in a supplement.
o LER 2-88-21, dealing with a mode transition made with the reactor cavity flow transmitter inoperable on November 27, 1988, states corrective action will be provided in a supplemental report.
o LER-2-88-22, dealing with a loss of both trains of Auxiliary Building Ventilation provides no root cause or corrective action and states a supplemental report will be issued.
o Special Report (SR) dealing with diesel generator, DG 1-3, failure to start on second level undervoltage on November 12, 1998, states a supplemental report will be issued on the cause of the failure.
These examples of failures to establish a schedule for assessing and correcting problem areas was discussed with licensee managemen The inspectors will continue to follow this area during routine inspection of LERs and other licensee reports.
No violations or deviations were identified.
10.
Inde endent Ins ection a.
Confi uration Mana ement Meetin On December 9, 1988, a meeting was held in the Region V, Walnut Creek office to discuss with the licensee their. Configuration Management Program (CMP).
Attending, the meeting was the Diablo Canyon Project Engineer, who leads the licensee's CMP task force, and the Region V Director of the Division for Reactor Safety and Projects.
Other attendees were as noted in Section 1 of this report.
The agenda for the meeting was essentially the licensee's discussion of the CMP provided as Enclosure 4 to their October 5, 1988, response to the Maintenance Team inspection.
The meeting began with a discussion by the licensee of how the CMP had progressed since its inception.
Specifically, the CMP task force developed a concept of what a complete CMP should include, then reviewed current practices at Diablo Canyon to determine what elements were in place and what enhancements were necessary.
The discussion then focused on the proposed enhancements described in the "General Improvements" section of Enclosure 4.
Of the topics covered, significant discussion focused on the following:
o The responsibility for and extent of review of plant mai ntenance and surveillance procedure revisions to assure work is performed consistent with design.
The licensee indicated that although the plant system engineers would be responsible for the task, the review function was not formalized.
o The breakdown of responsibility between IEC and Engineering control of Class 1 setpoints.
o The perceived lack of documentation of the basis for plant controlled setpoints.
o The Region's perception that plant system engineers, given new system responsibilities on top of existing responsibilities, have too many tasks to accomplish their overall function.
In addition, the licensee discussed the status and expected completion dates of the initial program.
The licensee stated that a
Configuration Management Policy document, the Design Criteria Memorandum (DCM) writer's guide, and a single document which identified the sources of design basis information will be in place by the end of 1988.
Pilot DCMs for the Auxiliary Feedwater, 4KV, and Nuclear Instrumentation systems are scheduled to be completed by the end of February 1989.
An Administrative Procedure describing the system engineering program will be issued mid-January, 198 The Region will review these as they become available.
Review of ualit Assurance Audit The inspector reviewed a licensee guality Assurance audit of technical specification implementation (audit report number 88831T).
The audit reported what appeared to be a technically important finding.
Specifically, the report indicated that setpoints used for reactor trip instrumentation were specified with different values in surveillance test procedures from those setpoint values given in the technical specifications and the licensee's scaling calculations (which are used to establish the surveillance test procedure setpoints within technical specification limits but also accounting for instrument inaccuracies and drift).
The audit report did not indicate whether there were immediate operability concerns but stated that any adverse impacts would be evaluated by plant staff.
The audit report was forwarded by memorandum from the Manager of guality Assurance to the president of PG&E and the Plant Manager.
The inspector discussed the audit with the IKC Manager who later determined that there were no immediate safety concerns.
He stated the problem to be an administrative one.
He stated that the auditors had reviewed out of date scaling calculations and had bee'n told that at the exit.
The resident inspector and his regional Section Chief discussed the matter with the gA Manager.
The gA Manager stated that the gA practice was to have plant staff evaluate gA findings for significance.
The inspectors related to the gA Manager their opinion that potentially significant findings should be quickly assessed for safety significance and action taken quickly if appropriate.,
The inspectors further considered that audit reports should reflect that appropriate assessments were quickly made and appropriate action immediately taken.
The inspectors expressed surprise that an audit report with such an apparently significant finding passed through the management chain and was issued without causing alarm and action.
The gA Manager agreed and indicated that appropriate guidance would be given to gA auditors.
c.
On-the-S ot-Chan e to Emer enc 0 eratin Procedure EP E-0 The inspector reviewed an On-The-Spot-Change (OTSC) to Emergency Operating Procedure EP E-0 to determine if the change should have been issued as an OTSC or should have been issued as a formal PSRC approved revision to the procedure.
Technical Specification 6.8.3 allows temporary changes to procedures if the intent of the
procedure is not altered, the change is approved by two members of the plant management staff, at least one of whom holds a Senior Operator license on the unit affected, and the change is documented, reviewed by the PSRC and approved by the Plant Manager within 14 days of implementation.
On September 9, 1988 an OTSC was issued on EP E-0 "Reactor Trip and Safety Injection" to add an additional step to stop one RHR pump if Reactor Coolant System pressure is greater than 300 psig.
The change was made in response to NRC Bulletin 88-04 which requested licensees to evaluate the potential for deadheading one or more pumps in a safety related system.
Specifically, it was found that at some plants, following a safety injection signal, if the reactor coolant system pressure remained above the shut off head of a set of safety-related pumps required for injection, resulting in the pumps operating in their recirculation mode, and if one train had higher operating characteristics than another, in some configurations, the second pump would not meet its minimum flow requirements, potentially resulting in its failure.
Following a performance test on the RHR systems for both units, the licensee determined that one pump for each unit was susceptable to a less than minimum design flow condition (less than 500 gpm) while in recirculation.
The licensee conducted a
PSRC meeting on September 8,
1988 to review a Safety Analysis/Justification for Continued Operation (JCO).
The safety evaluation included in the JCO was based in large part on a proposed modification to EP E-0 to "secure the RHR pump promptly if indication of RHR deadheading is observed."
This change was based on a recommendation by the NSSS vendor (Westinghouse)
to stop one low head safety injection (LHSI) pump before pump degradation or malfunction could be caused by deadheading.
The procedure was revised using the OTSC process following the conclusion of the PSRC meeting.
The Operations Manager determined in his review of the OTSC that the intent of the EP E-0 was not changed by the OTSC.
In addition he considered that the PSRC had essentially reviewed the change to the procedure in their meeting on the JCO.
The inspector reviewed the OTSC and found that the step to shut off one RHR pump was placed in an acceptable spot in the procedure.
On November 21, 1988, a follow-up formal procedure revision was completed.
In addition, the licensee received an evaluation from Westinghouse which states that an RHR pump can operate on recirculation at 290 gpm without deleterious effects.
d.
Seismic Induced Inaccurac in Residual Heat Removal Pum RHR Recirculation Valve Actuation Instrumentation The inspectors received information from the Trojan resident inspector regarding a Westinghouse letter to Trojan which described a problem with setpoints for Barton Model 288A flow switches.
The letter (POR-87-607 dated October 2, 1987, from Westinghouse to
Trojan) indicates that seismic qualification tests showed that the accuracies of the flow switches were affected and shifted from 2.55%
to 12.55% accuracy.
Westinghouse therefore specified revised actuation setpoints for the flow switch which affected the RHR reci rcul ati on flow actuati on points.
The Diablo Canyon I8C Manager and the Assistant Plant Manager were asked to determine if the situation applied to Diablo.
Plant staff investigated and determined that:
o Diablo uses Barton 288A flow switches.
o Diablo has the flow switch in the RHR recirculation system.
o Diablo had not been notified by Westinghouse that the problem applied to Diablo.
Subsequent telephone conversations between Westinghouse and Diablo Canyon were made.
Plant management stated that no immediate action was required based on the fact that Diablo had revised its emergency operating procedures (in response to an NRC information notice on pump deadheading)
to,have RHR pump flow checked early in an event.
Additionally, the likelihood of a seismic event was low and the consequences of premature or delayed recirculation flow had been preliminari ly evaluated by Westinghouse and determined to be satisfactory.
Westinghouse had been chartered, however, to provide revised setpoints for Diablo Canyon and were scheduled to provide the analysis and setpoints in February 1989.
Westinghouse had not notified Diablo because their records indicated a different model instrument had been supplied to Diablo Canyon.
The licensee committed to treat the situation as a nonconformance and to therefore determine root cause and corrective action to prevent recurrence.
The inspector will follow-up the licensee's resolution of this problem.
(Follow-up Item 50-275/88-32-01).
Power Ascension. Testin Lack of Acce tance Criteria On December 21, in review of the operator logs, the inspector noted an entry from December 20, 1988, which stated that the shift foreman for Unit 2 had been notified by engineering that "loop 2 and 3 delta T's" and "PT-505 and PT-506", "are out of spec but does not constitute inoperability."
The inspector discussed the meaning of the log entry with engineering and I8C management and determined that the out of specification condition referred to instrumentation process loop
outputs to various control and safety setting setpoints which were found outside arbitrary bounds set by engineering which then triggered recalibration to be performed.
The conditions were found during the planned calibration checks at power as part of power ascension testing.
The inspector reviewed the data and found the out of tolerance conditions to be in the conservative direction.
However, the inspector considered and the Assistant Plant Manager (APM) for Technical Services agreed that the procedure should have acceptance criteria bounds which would trigger a declaration of inoperability and possible power reduction.
The APM stated a procedure revision would be made prior to the next refueling outage.
No violations or deviations were identified.
ll.
0 en Item Follow-u 92703 92702)
a.
Bulletin 88-10 Molded Case Circuit Breakers 0 en On December 16, 1988, the residents received a written request from NRR to inform the licensee of the need to retain all breakers identified as unacceptable during testing and review, and to remind the licensee to report any other equipment identi'fied during routine receipt inspection or testing which is suspected of being counterfeit or fraudulently refurbished.
(Reference Grimes to Kirsch et al memorandum dated December 12, 1988).
The resident accomplished the requested action on December 16, 1988, at the Assistant Plant Managers for Operations daily meeting which was attending by maintenance and materials representatives.
No violations or deviations were identified.
12.
Unresolved Item An unresolved item is a matter about which more information is required to ascertain whether it is an acceptable item, a deviation, or a violation.
An unresolved item is documented in paragraph 4. l.
On January 13, 1989, an exit meeting was conducted with the licensee's representatives identified in paragraph 1.
The inspectors summarized the scope and findings of the inspection as described in this report.