IR 05000275/1989026
| ML16342B634 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/29/1989 |
| From: | Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F501 | List: |
| References | |
| 50-275-89-26, 50-323-89-26, NUDOCS 9001170348 | |
| Download: ML16342B634 (24) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/89-26 and 50-323/89-26 Docket Nos:
50-275 and 50-323 License Nos:
Pacific Gas and Electric Company 77 Beale Street, Room 1451 San Francisco, California 94106 Facility Name:
Diablo Canyon Units 1 and
Inspection at:
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
October 29 through December 9,
1989 Inspectors:
Approved by K.
E. Johnston, Resident Inspector P.
P. Narbut, Senior'esident Inspector
~ P<
~~~
ate
>gne Summary:
Ins ection from October 29 throu h December
1989 Re ort Nos.
50-275/89-26
~AI td:
Th i p ti i Id d ti i
p ti fpl t 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 30703, 37700, 37702, 37828, 40500, 61726, 62702, 62703, 71707, 73753, 90712, 92700, 92701, 92702, and 93702 were used as guidance during this inspection.
Results:
Areas of Meakness The inspection report describes five examples of valve and equipment lineup errors, although none of the incidents resulted in harm to individuals, equipment damage, or any significant safety concern.
Valve and equipment lineup errors was in-part, the subjec,t of significant enforcement.action taken in early 1989 and was followed by significant licensee corrective actions.
The inspectors expressed to plant management the need to critically:assess equipment lineup problems and their program of corrective.action.
At the end of the inspection period it was apparent that plant management was treating the events aggressively.
9001170~
gg00027-o 89122~
Fgp pQQcK c
pgg
DETAILS Persons Contacted J.
D. Townsend, Plant Manager
~D.
B. Miklush, Assistant Plant Manager, Operations Services M. J.
Angus, Assistant Plant Manager, Technical Services B.
W. Giffin, Assistant Plant Manager, Maintenance Services W.
G. Crockett, Assistant Plant Manager, Support Services W.
D. Barkhuff, Acting guality Control Manager T.
A. Bennett, Maintenance Manager D.
A. Taggert, Director equality Support T.
L. Grebel, Regulatory Compliance Supervisor
"H. J. Phillips, Work Planning Manager
"R.
C. Washington, Acting Instrumentation and Controls Manager J.
A. Shoulders, Onsite Project Engineering Group Manager M.
E.
Leppke, Engineering Manager
- S.
R. Fridley, Operations Manager R.
P.
Powers, Radiation Protection Manager E.
C. Connell, Assistant Project Engineer The inspectors interviewed several other licensee employees including shift foremen (SFM), reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, quality assurance personnel and general construction/startup personnel.
"Denotes those attending the exit interview.
0 erational Status of Diablo Can on Units 1 and
At the start of the inspection period (October 29, 1989), Unit 1 was defueled and Unit 2 was in Mode 3.
Unit 1 core reload commenced on, November 9, 1989, and was completed November 13, 1989.
The unit reached Mode 2 and criticality on December 10, 1989..
Unit 2 began the inspection period in a corrective maintenance outage for generator exciter work.
The Unit returned to 100K power operations on November 7.
On December 4, 1989, power was reduced to 54 to perform work on a piping leak associated with one of the main feedwater pumps.
On December 7, the Unit returned to 10(C power.
During this period, an Emergency Operating Procedure inspection (50-275/89-24)
was conducted and inspections related to the containment sump (50-275/89-31),
the Unit 1 spent fuel pool radiation monitor alarm (50-275/89-25),
and the use of a non-licensed shift supervisor (50-275/89-29)
were conclude then opened the IY-13 output breaker, which was located in the same room.
IY-13A is physically located in a separate room.
A licensee event report was issued on this subject (50-275/89-12, dated December 1, 1989).
The inspector found the LER acceptable.
Further examples of operator'ineup errors and inattention to detail are discussed in this report in section 4e.
On November 5, 1989, the Unit 1 fuel handling building ventilation system transferred to iodine removal mode when the spent fuel pool radiation monitor RM-58 went into high alarm.
The alarm setpoint was 14mr/hr.
No fuel movement activities were in process.
The radiation monitor was declared inoperable, the ventilation system was left in iodine removal mode, and a portable monitoring system was placed in service..
These actions were established in accordance with Technical Specification (TS) 3.3.3. l.
Based on this event and other events discussed in Inspection Report 50-275/89-25, the licensee has determined that the setpoint for RM-58 is too low for normal refueling activities.
As a result, they have initiated action to request a
TS amendment change.
~ The licensee submitted LER 50-257/89-13 on this subject on December 5, 1989.
The inspector found the LER acceptable.
Unit 1 Auxiliar Saltwater Pum Im eller Hard Facin De radation On November 13, 1989, during planned refueling outage maintenance work, the licensee discovered degradation of a hard faced wear ring on Auxiliary Saltwater pump l-l.
The pump provides vital saltWater to the component cooling water (CCM) system and is therefore the ultimate heat sink pump.
The pump was being inspected due to previously identified problems with improper impeller heat treatment due to improper sub-tier vendor quality assurance programs.
The pump is a Bingham Milhamette vertical shaft mounted pump, Model VCM.
The wear ring which degraded had been inseryice for one refueling cycle.
The ring is attached to the rotating impeller and is hardfaced by a metal spray technique to the stainless steel ring.
The ring is about two inches in height.
The nature of vhe degradation was. the loss of about one inch of the upper part of the hard facing material, apparently due to poor bonding with the parent metal.
The thickness of the hardfacing was about 1/32 inch based on pieces retrieved from the component cooling water heat exchanger head.
The effect of complete loss of the hard facing material would be expected to be an increase in pump internal bypass flow resulting in
C.
Ph s ical Securi t Security activities were observed for conformance with regulatory requirements, imp 1 ementati on of the site securi ty plan, and administrative procedure's 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.
No violations or deviations were identified.
4.
Onsite Event Follow-u (93702)
a ~
Auxiliar Saltwater Pum 2-2 Motor Power Ground On October 29 and October 31, 1989, while Unit 2 was in Mode
repairing damage to the main generator exciter bearing, a ground alarm for Auxiliary Saltwater Pump 2-2 annunciated in the control room.
The pump was declared inoperable and the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification action statement was entered on October 31.
Inspection and testing of the cable found the "A" phase grounded.
All three phases of the feeder cable in the section, where the ground was found, were replaced.
The cause of the ground was not visibly apparent although it was suspected that degradation had occurred in the insulation between the power line and the grounded outer shield.
Electrical maintenance sent sections of the grounded cable, sections of removed underground cable, and sections of new cable to the licensee's Technical and Environmental Services (TES) for analysis.
At the end of the inspection period the analysis had not been completed.
This item will be followed up in conjunction with Open Item 50-323/89-21-Q5 which relates to a plant management commitment to review the maintenance program with respect to plant aging in adverse conditions.
b.
Unit 1 Fuel Handlin BuHdin Ventilation Mode Chan es On November 2, 1989, Unit 1 operators in the process of removing instrument inverter IY-13A from service inadvertently opened the output breaker on the wrong instrument inverter (IY-13),
deenergizing instrument AC panel PY-13.
This action deenergized the new fuel storage area radiation monitor, RM-59, causing the fuel handling building ventilation system to transfer from the normal mode to the iodine removal mode (an Engineered Safety Features actuation).
The cause of the actuation was operator error.
In performing the clearance, the operator-and a verifier first placed instrument AC panel PY-13A (normally supplied by IY-13A) on back-up power.
They
- 3.
0 erational Safet Verification (71707)
a.
Genei al.
b.
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 (LGOs) 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}
Conduct of selected activities for compliance with the li.censee's administrative controls and approved procedures.
(d)
Interiors of electrical and control panels.
(e)
Plant housekeeping and cleanliness.
(f}
Engineered safety feature equipment alignment and conditions.
(g)
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 actiy'ities.
Radiolo ical Protection The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures
.and in compliance with regulatory requirements.
The inspectors..verified that health physics supervisors and professionals condu'cted 'frequent plant tours to observe activities in progress and were g'enerally 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 RMP (Radiation Mork Permit).
a decrease in achieved forward flow and perhaps increased vibration.
However, degradation was not noted in pump operation during the past operating cycle in regards to pump vibration or performance.
The licen'see suspects that at least one of the Unit 2 pump impellers has degraded hard facing.
It appears that unidentified metal fragments retrieved during an October 4, 1989, Unit 2 component cooling ~ater heat exchanger 2-2 cleaning (ASM side)
were in fact hard facing.
The licensee did not replace the hard facing or refurbish the impellers for Unit 1 or Unit 2.
A justification for continued oper ation (JCO)
and 50.59 evaluation was performed to justify this action.
The safety analysis contained in the JCO noted the following:
o The loss of hard facing could result in up to a 4X loss of pumphead.
The flow reduction could be accommodated within the margin of the pump flow above the minimum.
o
-
The hard faced surface is a recent design change from the initial uncoated design.
The initial design operated satisfactorily without wear-ring replacement.
Ha'rd facing maP come off in discrete pieces.
These pieces could travel through the ASM system and into the salt water side of the CCM heat exchanger.
The consequences of this are not notably different from the consequences other debris such as mussel shells which commonly travel through the system.
The pump quarterly surveillance test has been increased to a monthly frequency.
The licensee committed in the JCO to replace the hard facing during the next refueling outage for both units.
The inspector reviewed this analysis and found it acceptable.
Auxiliar 0 erator Found Aslee in Containment On November 17, 1989, the senior resident inspector was informed by the operations supervisor that an auxiliary operator on night shift in the containment during the Unit 1 refueling outage had been found dozing on the evening of November'2.
The auxili'ary operator's duties at the time were to standby in containment near a desk and phone to handle any work clearances or other operations miscellaneous duties that might be required during" the shift.
The individual stated to the operations supervisor that he had squatted down next to a containment wall and had dozed off.
The individual was discovered by a health-physics technician who reported to his supervisor, who in turn reported it to operations supervision.
The area in containment was one of low background'adiation levels.
The Iicensee management treated the matter with seriousness and took acceptable corrective action e.
Valve Lineu Errors
'n a number of occasions du'ring the inspection period, operators misaligned equipment while hanging clearances or performing system alignments.
On November 20, centrifugal charging pump 1-2 operated for 80 minutes without component cooling water (CCM) supplied to its motor or lube oil coolers.
CCM cooling supply valve CVCS-1-484B was found sealed closed when in fact it should have been sealed open.
Records of the system alignment show it had been sealed and verified open.
On November 21, an operator opened the DC power supply for the Unit 2 turbine driven auxiliary feedwater pump 2-1 steam supply when in fact the Unit 1 breaker was to be 'opened.
o On November 9, containment 'spray pump 2-1 ran dead-headed for approximately three minutes while performing inservice testing.
The recirculation valve, which is required to be opened in the test procedure, was left closed.
o On December 5, 1989, a valve lineup error during a,routine evolution resulted in a spill of ammonia in the condensate polisher area.
o Section 4 b of this report discusses a fifth example of-misaligning equipment.
None of the examples discussed above resulted in equipment damage or conditions beyond Technical Specification action statements.
However, they do show a marked increase in equipment lineup problems and inattention to detail.
As a result of these events, the operations manager took aggressive action.
An "all hands" meeting was held with all shift crews to stress awareness and use of all policies and procedures associated with proper component positioning.
Additionally, a "plant status control committee" will be formed by the operations manager and will include senior reactor operators from each crew.
The committee will review all procedures involving plant status control.
The group will establish a working knowledge of the procedures and will be tasked with disseminating the information to each crew member.
Plant managements actions appeared to be aggressive.
The inspectors will continue to follow the licensee's progress in valve and equipment lineups.
f.
Unit 2 Hain Feedwater Pum 2-2 Pi in Crack On December 3, 1989, a pin-hole leak developed in a Unit 2 number
main feedwater pump (MFM pp 2-2) equalizing line.
To repair the leak, the unit was reduced to 50X power and the pump taken out of servic g.
The leak was repaired using a special weld procedure to preserve the failure conditions for future evaluation.
The unit returned to power on December 7.
-The licensee inspected the equalizing lines for the other three MFW pumps and found no leakage.
At the end of the inspection period the licensee had not determined the root cause.
However, a quality evaluation had been initiated.and the pump vendor, which fabricated the line, had been contacted.
The line will be inspected during the upcoming Unit 2 outage.
The inspector will followup during routine inspection.
Auxiliar Steam Drain Receiver On December 5, 1989, the Unit 2 turbine driven auxiliary feedwater pump (AFW pump 2-1) room filled with steam while-operators were in the process of warming up the Unit 1 steam supply for AFW pump 1-1 as part of its return to service.
The AFW pump 2-1 was declared inoperable and its oil was inspected for water intrusion.
In the past year, the licensee has been increasingly aware of longstanding problems with the auxiliary steam drain receiver system allowing a steam environment to develop in the AFW pump 2-1 room.
The system engineer stated that a design change was in process to correct the problem which resulted in the December 5 event.
The inspector will review the licensee's actions in these areas in a future inspection.
Momentar Loss of Instrument Air Com ressors On December 7, 1989, instrument air pressure dropped from its normal range of over 100 psig to approximately 90 psig when three temporary air compressors were out of service.
The transient ended when operators restarted one of the temporary air compressors.
The licensee recognizes that the, four permanent air compressors are not sufficient to maintain air system pressure due to their relatively small capacity.
Two additional higher capacity rental air com~ressors have been used since plant startup.
A third
"backup'ir compressor was brought'n for the Unit 1 outage.
At the time of the event, the two rental units were out of service for maintenance.
The "backup" air compressor, which had been maintaining the base load, tripped for unknown reasons.
Three of the four permanent air compressors started but were unable to maintain pressure.
At the end of the inspection period, the licensee had not completed a review of the event.
The licensee does plan to make permanent modifications to the system and has scheduled their completion for prior to the Unit 2 refueling outage in March 1990.
The inspector will continue to follow the progress of the licensee's review of the above event and the modifications to the instrument air system.
No violations or deviations were identifie.
Maintenance (62703 The inspectors observed portions of, and reviewed records on, selected maintenance activities to assure compliance with approved procedures, Technical Specifications, and appropriate industry codes arid 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.
r a.
Maintenance Related to Unit 1 Boration Flo ath Valve FCV-llOA During the Unit 1 refueling outage, maint'enance was performed on boration flowpath valve FCV-llOA, which had been leaking past its seat.
A design requirement for FCV-llOA is that it pass 10 gpm.
During a boration flowpath test following the valve maintenance, it was found that FCV-llOA was only passing 3 gpm.
It-was discovered that the wrong "trim kit", a replacement stem, plug and cage, were used.
However, the trim kit used was the one specified in the valve design drawings.
Qn review, plant maintenance discovered that during plant startup testing (around 1977), the original trim kit had been replaced with one which, could pass 10 gpm.
The design drawing was not updated to reflect the change.
Due to a long lead time required to order a new trim kit and the urgency required to ~lace the valve back in service (at one point it was a 'critical path 'ob for change to Mode 4), maintenance fabricated a trim kit.
During a flow test following the reassembly of FGY-110A, the valve was found to be operating erratically.
It was discovered that a
spacer had been left out.
The spacer was reinserted and the valve performed satisfactorily.
The licensee was in the process of reviewinq two apparent problems; the 1977 failure to update plant drawings w>th 'as-built information and the failure to include the spacer into the assembly.
equality evaluations had'been issued.
The inspector will follow the licensee s actions in the course of routine inspections.
b.
Unit 1 Reactor Vessel Head Cables Found Outside Cable Tra s
On December 1, 1989, the inspector identified cables lying outside cable trays over the Unit 1 reactor vessel head.
The unit was in Mode 5, progr'essing towards Mode 4. 'n identical problem, of greater severity, had been identified on Unit 2 following its first refueling outage (Inspection Report 50-323/87-26).
In response to the inspector's findings, the licensee had electricians reposition the cables.
The electrical maintenance supervisor committed to review the program for vessel head cable-placement following refueling outages.
No violations or deviations were identifie Survei 1 lance
{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.
Review of Potential For Inadvertent Criticalit Durin Core Reload On November 9, 1989, prior to core reload, the inspectors reviewed the licensee's refueling procedures to assess whether the licensee had considered intermediate refueling configurations before achieving the final core configuration.
The licensee planned to use intermediate core configurations as a
tool to ease the placement of bowed fuel elements.
Essentially, when a bowed fuel element was to be placed, the licensee planned to form a "box" with four other relatively stra'ight fuel elements.
To facilitate this, required the movement of some fuel elements out of normal turn and the placement of some elements alongside the core baffle.
{the fuel vendor) supplied the licensee with core loading guidelines to ensure that shutdown margin was maintained in all configurations.
a The inspector reviewed the licensee's reload procedure, OP B-8D S2 and found that it.adequately incorpoiated the Westinghouse guidelines.
During the subsequent core loading process, the requirements of OP B-8D S2 were violated.
Section 5.5.3 of the procedure allows temporary storage of an assembly in a baffle location if it is separated from the core by at least two open cells.
With only six vacancies left in the core an element was placed in a baffle location which was not separated from the core by at least two open cells.
The element was placed against the baffle on two sides with the remaining faces adjacent to fuel.
The move was authorized by the reactor engineer, without obtaining a procedure change, who had judged that the move would have a negligible change in reactivity.
The violation of procedure was discovered by engineering during the
.post-refueling review of fuel movement.
The licensee discussed the'ove with Westinghouse which stated that the move had a negligible effect on reactivity.
A quality evaluation was initiated to track corrective actions.
This item was not brought to the attention of the inspector by the licensee and was discovered near the end of the inspection period.
This item wi 11 be carried as an Unresolved Item (Open Item 50-275/89-26-01).
Unit 1 Pressurizer Code Safet Yalve Hi h Set oint During the Unit 1 refueling outage, the three pressurizer safety valves
{8010A, B, and C) were removed and tested at a Westinghouse
test facility in Beaumont, California.
All three valves lifted at pressures greater that the 1X tolerance required by Technical Specification 3.4.2. 1.
The test results of the relief valve testing were as follows:
Yalve As Left As Found X Tolerance Deviation (7-88)
(10-89) -
(from 2485 psig)
8010A 2509 2667 7. 32X high 8010B 2499 2703 8.8X high 8010C 2470 2581 3.86X high As Left (Zo-89)
2494 2505 2504 The licensee determined that the shift resulted from the previous cycle of testing and setting during the Unit 1 second refueling outage.
The testing methodology used until the Unit 2 second refueling outage had been to drain the loop seal while at normal operating pressure and use a mechanical devise to simulate the additional pressure required to actuate the valve.
A Westinghouse letter to the licensee, received in October 1989, stated that
"... setting a valve at plant ambient air with steam as a media and installing it on a loop sea'1 filled with 300 degrees F water can result in a set pressure 4X to 8% higher than anticipated."
At the testing facility the methodology was to simulate plant conditions as near as possible to lift the valve using live steam while it had a
The licensee performed an analysis to determine the affects of the high liftpoints on the most limiting overpressure transient expected.
It was determined that for a loss of load/turbine trip transient, peak pressure could reach 2783 psia whereas the Technical Specification pressure safety limit is 2750 psia.
The 2750 psia pressure is based on 110X of design pressure.
The nonconformance report concluded that even though the Technical Specification safety limit could have been exceeded, the peak pressure would not have exceeded the faulted condition limit stresses of 120X of design pressure.
Additionally, with one pressurizer power operated relief valve in service, the licensee determined that pressure would not have exceeded 2724 psia.
The licensee performed a justification for continued operation for Unit 2, which was at full power.
Much of the analysis was based on the difference in testing methodology (the Unit 2 valves had been set at the test facility).
Additionally, one of the Unit 2 safety valves, which had leaked resulting in a shutdown, was retested four times with a loop seal and all four times was within the 1X tolerance.
When the same valve was tested three times without a loop seal, it lifted between 2 and 3.5X high.
Based on the above, the licensee concluded that the Unit 2 pressurizer relief valves were operable.
The licensee plans to continue the use of the testing facility to test the safety valves in conditions which duplicate actual operating parameters.
Additionally, the licensee committed to issue a voluntary licensee event report.
The inspector found these actions to be acceptabl No violations or deviations were identified.
7.
Licensee Event Re ort Follow-u (92700)
Status of LERs LERs 50-275/89-12 and 89-13 were closed out after review and follow-up inspections were performed by the inspectors to verify licensee corrective actions No violations or deviations were identified.
8.
Unresolved Items 9.
Unresolved items are matters about which more information is required to determine whether they are acceptable items, violations, or deviations.
An unresolved item is discussed in paragraph 6. a of this report...
Exit {30703)
On December 27, 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 repor e'