IR 05000206/1990013
| ML20043A668 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 05/02/1990 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20043A665 | List: |
| References | |
| 50-206-90-13, 50-361-90-13, 50-362-90-13, NUDOCS 9005220380 | |
| Download: ML20043A668 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-206/90-13,50-361/90-13,50-362/90-13 Docket Nos.
50-206, 50-361, 50-362 License Nos.
DPR-13, NPF-10, NPF-15 Licensee:
Southern California idison Company Irvine Operations Center 23 Parker Street Irvine, California 92718 Facility Name: San Onofre Units 1, 2 and 3 Inspection at: San Onofre Site, San Clemente, California Inspection conducted:
March 12 through April 6,1990
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Inspecto'r:
J. F B oi, Acting Project Inspector Approved by:
44 C TO P. H.
nson, Chief.
Date Signed Reacto Projects Section 3 Sumary:
L Inspection on March 12 through April 6, 1990 (Report Nos. 50-206/90-13, 50-361/90-13, 50-362/90-13)
r Areas-Inspected:
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An unan,raunced routine inspection by one regional inspector of various vital areas and equipment in the plant, and resolution of enforcement items, i
followup items, licensing event reports and part 21 reports.
Inspection Procedures Nos. 30703, 71707, 92700, 92701, and 92702 were used as guidance during the inspection.
Results:
1 General Conclusions and Specific Findings:
The licensee's actions taken to correct deficiencies resulting from
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inspection findings were thorough, timely, and properly documented.
Significant Safety Matters: None Sumary of Violations or Deviations:
None Open Items Sumary: Nine open items were closed.
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l 9005220380 900502 I
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PDR ADOCK 05000206 o
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P DETAILS I
1.
Persons Contacted Southern California Edison Company R. Berkshire, Electrical Engineering, Environmental Qualification (EQ)
Supervisor l
P. Blakeslee Station Technical, Supervising Engineer
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C. Brandt, Quality Assurance Engineer
- D. Brevig, Onsite Nuclear Licensing Supervisor S. Foglio, Station Technical, Electrical Engineer
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D. Hadley, Procurement Engineering, Supervisor D. Irvine.. Codes and Welding Supervisor G. Johnson, Sr., Compliance, Lead Engineer
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S. Khamamkar, Station Technical. Electrical Engineer R. Krieger, Manager, Operations D. Lowenberg, Station Technical, Mechanical Engineer J. Madigan Health Physics S. McMahan, Manager, Maintenance Engineering Services J. Morales Field Engineering, Supervisor
- S. Morris, Licensing Engineer
- J. Patterson, Assistant Manager, Maintenance
- R. Plappert, Manager, Compliance M. Ramsey, QA Supervising Engineer
- J. Reilly, Manager, Station Technical J. Robertson, Compliance Engineer D. Scholl Technical Training, Supervising Engineer
- M. Speer, Onsite Nuclear Licensing Engineer T. Vogt Plant Assistant Superintendent, U-2
- R. Waldo, Assistant Manager, Station Technical
- D. Werntz, Licensing Engineer W. Zint1, Technical Training, Supervisor San Diego Gas and Electric Company
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- R. Erickson, Senior Engineer
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City of Anaheim
- G. Edwards, Coordinator The inspector also talked with other licensee personnol during the course of the inspection.
- Attended the exit meeting on April 6, 1990.
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In addition NRC resident inspectors attended the exit meeting.
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2.
Area Inspection (71707)
An independent inspection was conducted in the Units 1, 2 and 3 Control and Auxiliary Buildings. The inspector examined areas and equipment for debris, potential hazards, oil and water leakage, and equipment condition; e.g., oil level, valve position, and electrical connection configuration and cleanliness. The equipment and areas inspected
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included:
i Unit I r
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4160V Switchgear Room, Buses 1C and 2C, and 480V Bus No. I
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480V Switchgear Room 2, Buses 2 and 3 c.
125V Battery Rooms 1 and 2 d.
Main Feedwater Pumps FWS-G-3A/3B
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Auxiliary Feedwater Pumps, G-10 and 10W f.
Diesel Generator Rooms 1 and 2 g.
Inverter / Battery for MOV 850C h.
Safety Injection valves HV 851 A&B, 852 A&B, 853 A&B and 854 A&B.
Unit 2 a.
4160V/480V Switchgear Rooms, Trains A and B b.
D-G Rooms 2G002/2G003, Trains A and B
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c.
Units 2/3 Remote Shutdown Room, Panels for Units 2 and 3 d.
Battery Rooms 2DI, 202, 203, and 2D4 Unit 3
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4160V/480V Switchgear Rooms. Trains A and B b.
D-G Rooms 3G002/3G003, Trains A and B c.
Battery Rooms 3D1, 3D2, 3D3, and 304 Those minor housekeeping items found during the walkdown of the above i
areas were brought to the attention of the licensee and were corrected.
In Unit 3 battery room 3D2, a scaffolding platform was in the process of being erected over the battery under maintenance order (MO) 89030649.
This maintenance order was examined and found to have been prepared for installing a permanent battery charger for maintaining a charge on the spare battery cells stored in this room. The M0 identified procedure 50-
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123-I-1.34, " Scaffolding Erection," to be followed when erecting
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scaffolding. The procedure was examined and the issue was reviewed with the licensee's cognizant engineer and seismic engineer.
It was concluded that the platform had been erected in accordance with seismic requirements.
Housekeeping and equipment status appeared to be acceptable.
No violations or deviations were identifie,
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3.
Followup of Previously Identified Items (92701)
a.
(Closed) 50-206/87-29-04, Problems With Control of Temporary Plant Modifications l
This item involved two temporary plant modifications.
The modifications were made to protect outdoor safety related equipment from unusually low temperatures. One of these modifications was made under a maintenance order which was not reviewed by cognizant station technical personnel. The second modification was accomplished without a procedure or involvement by cognizant station technical personnel.
The licensee's corrective actions consisted of reviewing the program for temporary field modifications (TFMs) and making changes to procedure S0123-XV-5.1, " Temporary Modification Control," to i
preclude recurrence of the concern.
The inspector reviewed the changes made to procedure 50123-XV-5.1 by Revision 1, which addressed the concern. The inspector also verified with the cognizant system engineer that the two temporary modifications, having served their purposes, had been removed. This item is closed.
b.
(Closed) 50-206/89-06-01, Reactor Coolant System Leak
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This item involved.the failure of Operations personnel, upon recognizing a reactor coolant system (RCS) leak rate of ap)roxi-j mately 11 gpm when the plant was in Mode 5 to make a one-1our
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notification to NRC as required by operating procedure S0123-0-14.
This item was retained as an open item pending completion of the licensee's root cause evaluation.
While pressurizing the RCS to run reactor coolant pump (RCP) "C",
the RCS was filled and pressurized to 145 psig and a leak rate of approximately 11 gpm was calculated.
It was thought at the time i
that the leakage was from the RCP "A" seal pack, and attempts were made to reseat the seal pack, including raising RCS pressure to approximately 200 psig.
In the process of raising RCS pressure, RCS leak rate increased to 33 gpm and further attempts to reseat the
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seal pack were unsuccessful. The RCS was depressurized to atmospheric pressure, and the calculated RCS leakage remained at 22 gpm. Leakage greater than 7 gpm is a one-hour reportable event pursuant to S0123-0-14 and 10 CFR 50.72, section b.1.ii.
This was i
not recognized until after the evolution was completed 5 five hours later. A Red Phone notification was made at approximately 7:00 a.m.
(March 29,1989).
Poor procedure utilization by the operator was the root cause for failing to recognize a one-hour reporting requirement. S01-2.1-5.
" Reactor Coolant System Leakage," was reviewed in a cursory fashion since it was perceived that it was not applicable to mode 5.
This lack of an adequate review resulted in the operator's not reading l
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the statement directing the Shift Superintendent to determine if the event should be classified as an emergency or reported per
S0123-0-14. A major contributor was the mind set that the unit was in mode 5, and that in this mode the RCS leakage limits of Technical Specification (TS) 3.1.5 did not apply. Also, the way the procedure was written made it possible to interpret the review process as not
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required. 50123-0-14 was later reviewed to determine whether there e
was any long term reporting requirement. This led to the discovery,
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after discussion and interpretation by Operations Management, that a one-hour report was necessary.
- The licensee took the following corrective actions to preclude the
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repetition of this occurrence:
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Requested the training department to include reportability
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requirements as part of the licensed operator requalification
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curriculum,
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Required ths personnel involved in the occurrence to be counseled on the importance of implementing procedures,
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Reviewed the abnormal occurrence instructions to identify any potential for mode 5 and 6 enhancements, and i
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Revised the applict.ble procedure to more clearly define the reporting requirements for an unisolable leak in the RCS.
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The inspector verified that the above corrective actions were
completed and concluded that these corrective measures were adequate. This item is closed.
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(Closed) 50-206/88-12-01, " Containment Spray Flow Low" Annunciator Circuit. Design Change 79-09
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l In reviewing nonconformance reports (NCRs), NCR S01-P-6052 was found
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to have identified a design change (79-09) which was prepared to correct a deficiency whereby the " Containment Spray Flow Low" annunciator circuit was not wired in accordance with the wiring and elementary drawings-However, the design change was never
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implemented. Because this alarm is an informational alarm for the
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operator and has no safety significance, it was assigned a low work priority. Consequently, all of the design package was not completed '
until late 88/early 89. Some preliminary work such as drilling
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holes for installation of conduit for this installation was accomplished during the Cycle X refueling outage in 1989. The balance of the work is to be completed during the next refueling j
outage scheduled to start in June 1990.
The inspector reviewed the schedule of NCRs planned for closure during U;'it 1 Cycle XI, the 1990 refueling outage, and determined that NCR S01-P-6052 is scheduled to be completed during this outage.
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The schedule for completion of this NCR is acceptable..This item is
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closed.
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(Closed) 50-206/89-07-02, Steam Generator Wide Range Level
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Instrumentation The licensee's corrective actions in response to Unit 1 LER 88-20-00 were examined, evaluated, and addressed in Region V inspection report 50-206/89-07 dated June 23, 1989. The inspector continued
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this issue as a followup item because of following two concerns; 1)
the use of current-limiting fuses, and 2) the results of post-modification testing during power escalation.
Background l
The licensee determined that the steam generator wide range (SGWR)
level. indicators LI-450A, LI-451A and LI-452A were not powered by a Vital bus.
This was contrary to the licensee's commitment for
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addressing post-TtlI Action Plan Item II.E.1.2.
The licensee further identified that the SGWR level indicators were not environmentally
qualified.
The licensee issued Revisions 2 and 4 to Design Change Package (DCP)
3364.00TJZ to correct these deficiencies. The DCP converted existing narrow range steam generator level transmitters LT-2400A, B, and C (Train A) and LT-3400A, B and C (Train B) to wide range, environmentally qualified level indicators.
In addition, the power supplies for level indicators LI-450A, LI-451A and LI-452A were changed from plant lighting panels to vital buses.
Current-limiting fuses were used for isolation purposes in the level instrument
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circuits.
Followup
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1)
The.inspectorexaminedSCEdrawings(Unit 1)455693-5, b68336-35, 568338-30, and 568342-12; and determined that I amp current limiting fuses were used in the circuitry for the steam
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generator wide range level instruments. The use of I amp fuses
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2)
During startup from the Cycle X refueling outage in May'1989, l
the plant experienced an inadvertent start of an auxiliary
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feedwater pump on low steam generator (SG) level. While-
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manually controlling SG 1evel at about 45% of narrow range, the l
new wide-range instruments were reading much lower, and one.
l channel initiated auxiliary feedwater at the equivalent level
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l of about 5%.
It was apparent that the new wide-range
indicators were reading low; the apparent error increased with power level. The source of the problem was traced to the
existence of a "downcomer flow resistance plate" in the steam generator. The existence of this plate had not been considered by SCE when it designed the new wide-range instruments. Since
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the wide-range variable leg tap was below this plate and the reference leg was above it, the dynamic pressure drop across the plate (and to a much lesser extent, downcomer flow
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resistance) caused a false low level signal. The magnitude of the effect was such that auxiliary feedwater would initiate at power, which was unacceptable from an operational standpoint.
The licensee developed a. test program to be conducted during power escalation, after the level indicating channels were modified to provide correct indicator performance, to verify the assumptions with regard to "downcomer flow performance", as used in the calibration of wide range level indicators. These test results were discussed with the licensee's cognizant engineer who had developed the test program. The test _results clearly verified the assumption of the downcomer flow perform-ance on calibration between tot and cold wide range level indicators and with the S/G narrow range level indicators.
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The inspector concluded that the licensee's actions in response to these two concerns (use of current limiting fuses and the results of postmodificationtesting)areacceptable. This item is closed.
e.
(Closed) 50-206/361/362/89-10-P, Part 21 Report, Commercial Grade Nonqualified ASCO Solenoid Valves The concern of this Part 21 report was that due to an incorrect angle of the valve seats, there is a possibility that certain Automatic Switch Company (ASCO) solenoid valves may be unable to open at the rated pressure and/or that the core discs of these valves may prematurely fail.
The licensee received a letter from ASCO dated February 14, 1989 which ASCO stated that model 8223A3 2-way solenoid valves could be subject to the above described failure. The licensee determined from a record search that only one such valve was purchased and that
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its serial number (S/N) was 14853K.
Further record review deter-mined that the valve was purchased and installed in 1981 in the Unit I auxiliary feedwater system.
The ASCO valve was re) laced in the system on or before March 1988 by SI-AFW-523, a chec< valve. The ASCO valve, S/N 14853K was found in the warehouse and as a followup to the above Part 21 letter from ASCO was scrapped on August 17, 1989.
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The inspector reviewed warehouse records and a warehouse order that demonstrated that the ASCO valve was scrapped. This Part 21 report is closed.
No violations or deviations were identified.
4.
Review of Licensee Event Reports (90712/92700)
a.
(Closed) 50-361/LER 88-033-00, Improperly Posted Fire Watch Due To Personnel Error This LER reported the failure of operating personnel to fully implement TS requirements when a fire door located on the corridor i
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near the main entrance to the auxiliary building control area was found to be inoperable. An hourly compensatory fire watch was implemented rather than the continuous fire watch required by TS 3.7.9 when fire zones on both sides of an inoperable door do not
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contain operable fire detection systems.
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The required compensatory measure was not appropriately implemented because,(contrary to procedural requirements, the Emergency Service Officer ES0) and the ES0 Shift Captain failed to evaluate the
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impairment in accordance with the criteria contained in applicable procedures. Had the procedures been followed closely, the.need for the compensatory fire watch would have been properly determined.
The licensee initiated the following immediate corrective actions:
1)
The authority of the personnel involved to initiate and approve impaiments was immediately suspended.
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The event was discussed with the personnel involved, and reinstruction was provided on procedural requirements associated with impairments.
The licensee initiated the following planned corrective actions:
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1)
The training program for all ES0s and ESO supervision will be enhanced to include procedural requirements associated with impairments. This training program enhancement will be applicable for periodic training as well as initial training of such personnel.
2)
Fire Protection Information System (FPIS) program enhancements to provide additional checks to preclude recurrence of similar
errors was scheduled to be implemented by mid-1989.
The inspector examined documentation which demonstrated that the planned corrective action described under Item 1) above was completed on January 26, 1989 and that the actions under item 2)
were. completed on December 27, 1989.
It was concluded that the
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immediate and planned corrective actions were adequate. This item
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is closed.
b.
(Closed) 50-206/LER 89-02-00 Positive Reativity Addition Due to Cognitive Error
This LER reported a positive reactivity addition to the reactor core on January 23, 1989 due to the inadvertent addition of 440 gallons of unborated decontamination water to the primary system while in Mode 6 with the reactor vessel head removed. The addition of positive reactivity while in this mode is prohibited by the Technical Specifications. The boron concentration of the reactor coolant was reduced from approximately 2663 ppm to 2626 ppm. Also, TS 3.8 requires that, while the unit is in Mode 6, the boron
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concentration be maintained greater than 2000 ppm and that the
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shutdown margin be maintained greater than or equal to.5% delta k/k.
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There was no safety significance to this event since the minimum
required shutdown margin of 5% (equivalent to 1900 ppm boron concentration during this refueling operation) was not approached, i
Beginning at 4:00 a.m. and continuing through about 11:00 p.m. on
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January 23, 1989, intermittent positive reactivity additions
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occurred as the reactor refueling cavity water level was being reduced and the cavity surfaces were decontaminated with unborated
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water. The control room supervisor (CRS) authorized the decontamination, which required a small quantity of unborated water to be used. The amount prescribed would have changed the RCS boron
concentration substantially less than 1%. This value was thought by
the CRS to not constitute a positive reactivity addition as it was within the accepted accuracy limits for analytical determinations of boron concentration.
The licensee took the following corrective action to preclude the repetition of a similar occurrence:
1)
Completed Corrective Actions:
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This event had been reviewed with appropriate decontamination and operations personnel.
2)
Planned Corrective Actions:
a)
Guidance provided to operators concerning control of positive reactivity additions will be enhanced to more explicitly define activities which constitute permissible positive reactivity additions and the limits imposed on those additions.
Develo) ment of the enhanced guidance will include exploring tie possibility of an allowable reduction in the boron concentration as the result of
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dilution which, with appropriate controls, would not
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cohstitute a TS violation when positive reactivity additions are prohibited. Operators will be required to read and acknowledge the enhanced guidance.
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Appropriate operating and decontamination procedures will be modified to provide controls which assure that decontamination activities do not result in reactivity addition contrary to TS requirements.
The inspector verified that the above corrective actions were completed by discussing the corrective actions with supervisors
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in Health Physics (decontamination) and Operations, and examining the following documents:
Operation divisional investigation report (0DIR) 1-89-1,
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and " Acknowledgement of Information" sheets.
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t Procedure S0123-VII-8.6.2 Revision 2 dated 11/17/89,
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" Decontamination Work Planning"~
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Procedure resolution request 3870, procedure S01-4-26 and
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attached status sheet dated 4/3/90
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ODIR :1-09-1, which described and evaluated (for -lessons learned) the event, was circulated to all shift personnel.
Acknowledgement informtion sheets which accompanied the ODIR identified,the personnel who had reviewed the ODIR, along with
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the date reviewed. Tailboard meetings on'this event were also
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i conducted with Operations and decontamination personnel.
Health Physics Procedure 50123-VII-8 had been revised to avoid.
a similar event.
The corrective actions taken to preclude the recurrence of this
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event are considered adequate.
- This item is closed.
No violations of NRC requirements or deviations were identified.
-5.
Follow-up on Items of Noncompliance and Deviations (92702)
a.
(Closed) 50-361/89-11-01; Enforcement
" Inadequate Corrective Action Concerning Gama-Metrics Connectors and 50.49 ReQJirements."
The issues involved in this enforcement item are fourfold:
1)
The requirements of 10 CFR-50.49(f) were not met. 10 CFR
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S0.49(f) requires that each item of electric equipment important to safety be environmentally qualified.
2)
The requirements of 10 CFR 50.49(j) were not. met.
10 CFR
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50.49(j) requires that a record of the qualification be maintained to permit verification that each item of elec; P.
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equipment important to safety is qualified for its applica W
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and meets its specified performance requirements when it is subjected to the conditions predicted to be present when it must perform its safety function.
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3)
The licensee's nonconformance report (NCR) and 10 CFR 50.59 evaluation did not-provide an adequate assessment or l-documentation in accordance with 10 CFR 50.49 requirements.
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particular, the 10 CFR 50.59 evaluation credited alternate l-instrumentation for accomplishing the safety function despite l-the fact that none of the listed variables provides real time L
core reactivity information.
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No administrative controls were established (e.g., control room
operators were not notified of the potential for these monitor L.
to fail during post accident conditions).
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Background and Reasons for the violation This enforcement item identified a concern with regard to the licensee's safety. evaluation and decision to " accept-as-is" Gamma-Metrics cable connectors used on the startup log power excore i
neutron monitors.
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On February 19, 1988, Gamma-Metrics issued a 10 CFR Part 21 notification of a potential deviation in which certain connector j
solder joints could leak at elevated temperatures. These connectors
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were used in Units 2 and 3 excore monitoring systems..In this Part 21 report, licensees were requested to send spare conxctors to the:
vendor for testing. SCE complied with that request and sent one connector that was located in stores. The vendor tested connectors that were sent and revised their Part 21 report as a result of the failures that were found. On May 10, 1988, the vendor sent a second letter that stated the following:
"The results of these tests convince us that there is a significant possibility of having leaks
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in cable assemblies which are installed in our customers'
facilities."- The vendor also stated that a leak in the cable assembly could cause the neutron flux monitoring channel performance to be degraded ~or to fail during a design basis accident.
On May 12, 1988 SCE received a copy of a 10 CFR 21 Report from Gamma-Metrics concerning the solder connections on their cable -
assemblies. SCE.uses the NCR process, with its safety evaluation and corrective actions, in conjunction with a written justification for continued operation (JCO) to satisfy 10 CFR 50.49 environmental _
qualification requirements. On June 13, 1988,-Nonconformance Report'
G-0865, Rev. O, was initiated to document the Gamma-Metrics 10 CFR
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Part 21 report concerns. The NCR was reviewed and approved on August 2, 1988. Additional background on this enforcement item can be found in Region V inspection report 50-361/362/89-11.
SCE admitted that the environmental qualification record for the
Gamma-Metrics flux connectors was not maintained in accordance with
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10 CFR 50.49. SCE also acknowledged that when notified by the vendor (via a 10 CFR 21 Report) that the environmental qualification for the connectors could not be assured, SCE did not adequately
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perform the requisite safety evaluation and justification for
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l continuedoperation(JCO).
Immediate Corrective Steps Taken to Resolve This Enforcement Item
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The following imediate corrective steps were taken to correct this
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1)
A special order was issued on April 14, 1989, to alert operators to the potential for failure of the flux connectors in a post-accident environment.
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A' caution sticker was placed on the equipment in the control room which stated "May fail high during accident-conditions" to-.
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alert the operators of the potential failure mode.
3)
TheUnits2/3EmergencyOperatingInstructions(E01s)were
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revised to direct operators to comence emergency boration upon
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indications of unexpected increasing reactor power level or-
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inadequate shut down margin, j
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SCE had previously developed a training program to improve the quality of engineering and technical work / review in NCRs and 10 CFR 50.59 safety evaluations. As of February 28, 1989, the
training program was considered fully implemented.
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5)
Engineering personnel who prepare and review'JCOs have been instructed in the requirement to include all applicable corrective actions and administrative controls.
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The QA organization is conducting enhanced training of appropriate personnel performing NCR reviews.
7)
The NCR review process has been enhanced to direct NCRs to cognizantQAandIndependentSafetyEngineeringGroup(ISEG)
engineers.
In order to verify the completion of the above corrective actions,
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the inspector examined the following documents associated with.the above items:
Operations Special Order 89-06 and acknowledgement of
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information sheets.
NonconformanceReport(NCR)G-0865-
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Lesson Plan and attendance sheets for NCR training for QA, QC,
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and ISEG engineers, given during June 1989.
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These documents appeared to be in order and demonstrated that the above corrective actions were initiated / completed.
It is concluded
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that these corrective actions addressed the concerns and are
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adequate.
Corrective Actions Taken During Cycle 5 Refueling Outages The problem with the Gama-Matricss excore neutron detectors (startup channels) was outgasing at high temperatures of flux entrained in the solder. This allowed intrusion of moisture through the solder at LOCA and HELB pressures / temperatures, thus degrading the performance of the neutron flux monitoring channels. The excore neutron detectors are integral with approximately seventy feet of cable. An in-containment cable assembly (approximately 255 ft.)
connects the detector cable to the containment penetration. These
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cables are contained in a corrugated light metal condu'it which is encased in a braided metallic sheath. The corrugated conduit'and sheath are soldered to the connectors.
During the Cycle 5 refueling outage for unit 2 (Fall 1989), the detector and in-containment cable assemblies for the two startup channels were tested under the direction of a factory representative to determine if any of the cable connectors were leaking. Leaks" were found in some of the cable connectors which terminate the ends of the in-containment cable assemblies. To resolve these findings, the in-containment cable assemblies-for the two startup channels for unit 2 were replaced. The same corrective actions, testing and
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repairing / replacing as required, are planned for the two neutron detector startup channels of unit.3 during its Cycle 5 refueling outage scheduled to commence in mid-April 1990.
The inspector verified the completion of work for the replacement of cable assemblies for the two startup. channels of excore neutron detector for unit 2 by examining the following records:
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1)
M0s 89033759, (channel 1)and 89061891 (channel 2): Linspect, j
test: and repair or replace detector with integral cable,.
in-containment cable and splinter, as necessary, prior. to
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return to service from cycle 5 refueling outage.
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2)
M0s 89090285 (channel 1) and 89090286 (channel 2): Provide
vendor repair work on cables (if required) on site.
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3)
M0s 8907247 (channel 1) and 89072436 (channel 2):
Replace cable and perform pre-and post-installation testing of cable. -
'4)
PurchaseOrder(P0)No.6WO79020andP0requisitionnumbers
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12371 and 12376 for two Gamma-Metrics cable assemblies.-
5)
Vendor's certificate of conformance and shipping documents associated with the above P0.
6)
. arehouse/QC receiving documents associated with the above P0.
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-The inspector reviewed this item with the cognizant engineer and the
. licensee's environmental qualification (EQ) specialists. The EQ
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section was involved in the modifications which resulted in changing out the incontainment cable assemblies, and was revising and L
updating the EQ files for these cable assemblies.
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The inspector concluded from the review of the above documentation l
for the described corrective actions that the licensee's response to
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This enforcement item is closed.
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(Closed) 50-206/89-16-04; Enforcement
" Failure To Take Generic Corrective Action on Thread Engagement Issue."
The issue of concern in this enforcement item was that Unit 1 Nonconformance Report (NCR) S01-P-7294 dated June 28, 1989 did not
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establish the cause for identified inadequate thread engagement on fasteners on the east safety injection pump.
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In June 1987, a support plate was added behind the existing bracket on the east safety injection pump. As a. result of the. increased
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thickness of the support plate, when the maintenance worker
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reinstalled the nut on the bolt, the available bolting exposed' for thread engagement was reduced. The maintenance worker apparently
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did not realize that the "one thread of the stud or bolt should r
extend above the nut" requirement specified in the SCE Torque Manual
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was not satisfied, and he did not initiate an NCR.
When the NRC identified the subject condition (apparent incomplete bolt to nut thread engagement) NCR S01-P-7294 was issued on June 28, 1989. SCE procedure S0123-XV-5.0, "Nonconformance Report.
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System", steps 6.8 and 6.11.1, required that Block 26 " apparent cause", be completed as determined by Station Technical's evaluation of whether there is a need for a formal root cause analysis.
When deciding whether to require a root cause analysis, Station
. Technical personnel exercised judgement in deternining that a formal root cause analysis was not. appropriate in this instance. Their decision was based upon the belief that the observed. thread to nut.
- engagement had been reviewed by the design engineer, when he o
prepared the design to add the " support plate" and.by 0A at the time the installation had been accepted.
In summary, SCE has concluded that the reason a root cause analysis-was not performed was the judgement of the engineers that the NCR.
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procedure did not require one in this case.
Corrective Steps That Have Been Taken And The Results Achieved
- i In August 1989, a review of the Guidelines for Root Cause Evaluation
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was initiated in order to incorporate the guidelines into permanent-
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station procedures by November 30, 1989. The procedural revision under development will provide better guidance on when a formal root cause analysis is required and how to document that determination.
To verify the completion of the above corrective action, the inspector examined temporary change notice (TCN) 0-1, dated 11/12/89, to General Technical Procedure 50123-XV-31 Revision 0.
This change incorporated attachment 1, " Guidelines for Root Cause Evaluation," and attachment 2, " Developmental Resources," in Procedure S0123-XV-31. The procedure changes introduced by TCN 0-1 demonstrated the completion of the above corrcctive action.
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Corrective Steps That Will Be Taken To Avoid Further Violatior.s
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As a result of previous concerns relating to thread engagement, SCE
performed a walkdown of Units 2 and 3 to identify and correct
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instances of inadequate thread engagement.- Identified deficiencies were evaluated and repaired or reworked, as appropriate, A Unit l'
thread engagement walkdown was to be completed by January 31, 1990.
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To verify the completion of the above corrective action, the
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inspector examined the following documents-t
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1)
Minutes of a meeting held 12/13/89 to organize Unit 1 thread
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engagement inspection.
2)
Report of Unit I thread engagement inspection results, 1/19/90.
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Unit 1 thread engagement inspection, status table.
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Thread engagement calculations,-DC-3338.
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The results of the thread engagement inspection resulted in 190-findings. Of these, 33 were determined to be on safety or safety related equipment or systems.
Eight of these instances of inadequate thrend engagement had been corrected by installing longer bolts or studs. One of the 33 findings was awaiting delivery of material before corrective-action could-be completed. The the minimum strength of engagement (y Station Technical.to determine-balance of 24 were being evaluated b i.e., minimum number of threads which must be engaged) to-develop full strength of the fastener.
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Proper thread engagement is defined as follows:
"A minimum of one
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thread of the stud or bolt should extend above the nut."
In those
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cases examined by the inspector.where proper thread engagement had not been achieved, the bolts or studs were shy of proper thread
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engagement by only 2, 3, or 4 threads.. _The inspector examined in L
detail the thread engagement calculations, and determined that the L
minimum strength of engagement of the threads to develop full i
f strength for bolt sizes 3/8 to 7/8 inches diameter is 4 to 6 for L
fine threads and 3 to 4 for coarse threads.
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The licensee's program called for evaluating those bolts and studs which did not have proper thread engagement, and replacing immediately those which did not meet minimum strength of engagement.
Those bolts or studs that satisfy the minimum strength of engagement will be replaced when the piece of equipment or system of which they are a part comes down for normal maintenance. This program is considered acceptable.
The inspector concluded from the review of tne above documentation
for the described corrective actions that the licensee's response to
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No violations or deviations were identified.
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Exit Meeting.
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An exit meeting was held with members of the. licensee's staff (see paragraph 1) on April 6, 1990. The specific concerns addressed in this report were discussed with the licensee during this meeting and were-acknowledged by the licensee.
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