IR 05000397/1985037
| ML17278A558 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 12/16/1985 |
| From: | Johnson P, Toth A, Waite R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17278A556 | List: |
| References | |
| 50-397-85-37, NUDOCS 8601080307 | |
| Download: ML17278A558 (30) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report No: 50-397/85-37 Docket No:
50-397 Licensee:
Washington Public Power Supply System P.
O. Box 968 Richland, Wa.
99352 Facility Name:
Washington Nuclear Project No.
(WNP-2)
Inspection at:
WNP-2 Site near Richland, Washington Inspection Conducted:
November 4 - 27, 1985 Inspectors:
A. D. To
, Senior Resident Inspector 4C R.
S.
a te, Resident Inspector (Novem r 4-7, 1985)
/I</d'W Date Signed (~
r Date Signed Approved by:
P.,H.
nson, Chief React r Projects Section
>~/c zs Date Signed Summary:
tr Ins ection on November.4 - 27 1985 '(50-,397/85-37)
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t Areas Ins ected:
Routine inspection by the'resident inspectors of control room operations, engineered -safety, feature (ESF) status, surveillance program, maintenanqe program, licensee event reports, special inspection topics, and licensee action 'on previous'inspect'ion findings.
During this inspection, NRC Inspection Procedures 40704; 93702, 92703, 30703, 61726, 62703, 61702 and 71714 were covered.
E This inspection involved 116 inspection-hours on site by two resident inspectors, including 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> during backshift or weekend work activities.
Results:
Of the eight areas inspected, a violation was identified in the surveillance program,'i.e.
failure to follow administrative procedures for control of locks on secured valves (Para. 5).
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DETAIIS 1.
Persons Contacted Washin ton Public Power Su l S stem NJ ~
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~",F Powers, Plant Manager Baker, Assistant Plant Manager Corcoran,'Operations Manager Beardsley, Assistant Operations Manager Cowan, Technical Manager Harmon, Maintenance Manager Graybeal, Health Physics and Chemistry Manager Feldman, Plant equality Assurance Manager Peters, Administrative Manager Powell, Licensing Manager Aeschliman, Senior Licensing Engineer Wuesterfeld, Reactor Engineering Supervisor Kugler, Technical Manager Engineering Gelhaus, Nuclear Systems and Analysis Manager Martinez, Nuclear Systems and Analysis Engineer Bosi, Stress Analysis Manager Davison, Compliance Engineer Denchel, Planning'Engineer Mertens, Compliance Engineer Walton, Principal Maintenance Engineer General Electric Com an
- Nuclear, Ener Services G. Hayes, Engineering Site Manager
>'ersonnel in. attendance at exit meeting I
The inspectors also interviewed various control room operators, shift supervisors and shift manager',
engineering, quality assurance, and management personnel relative to activities in progress and records.
2.
General
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The Senior Resident Inspector and/or'he Resident Inspector were on site November 4-8, 11-15, 17-22 and 25-27. Backshift inspections were conducted November 4, 5, ll, 12, 13, and 17,.
3.
Plant Status The plant operated with one recirculation loop out of service, at about 72/ throughout the month, with exception of brief unplanned shutdowns at the middle of the month.
A 100-day continuous run had been achieved prior to the first unplanned shutdown November 1 ll'3, A'I, I" r II r
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4.
0 erations Verifications The resident inspector reviewed the control room operator and shift, manager log books on a daily basis for this report period.
Reviews were also made of'the Jumper/Lifted Lead Log and Nonconformance Report Log to verify that. there were no conflicts with Technical Specifications and that the licensee was actively pursuing corrections to conditions listed in either log.
Events involving unusual conditions of equipment were discussed with the control zoom personnel available at the time of the review and evaluated for potential safety significance.
The licensee's adherence to Limiting Conditions for Operation (LCO's), particularly those dealing with ESF and ESF electrical alignment, were observed.
The inspector routinely took note of activated annunciators on the control panels and ascertained that the control room licensed personnel on duty at the time were familiar with the reason for each annunciator and its significance.
The inspector observed access control, control room manning, operability of nuclear instruments, and availability of on site and offsite electrical power.
The inspector also made regular tours of accessible areas of the facility to assess equipment conditions, radiological controls, security, safety and adherence to regulatory requirements.
For this period, the following are examples of specific items considered by the inspectors:
a
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Caution tag
$/659, and danger tags associated with clearance orders 85-11-89 and 91 were properly logged and affixed to affected equipment.
The danger tags were filled out in advance, and used by the equipment operator in conjunction with the clearance order to assure that every valve was properly positioned and tags affixed.
Iocations of mechanical jumper
$1103, elect'rical jumpers A/95 through
$/98, and status of lifted lead tags 924, 25, 36, 37 were determined to be as documented in the control logs.
b.
Reactor Scram procedure 3.3.1 (Revision 3) and Reactor Trip and Recovery Procedure 1.3.5 (Revision 4) were implemented during the Scrams which occurred November 13 and 17.
The inspector observed use of procedure 3.3.1 by an operator, and the conduct of a post-trip review meeting of shift personnel shortly after the plant had been brought into a stable condition, in accordance with procedure 1.3.5.
The two procedures provided detailed instructions for evaluation of the scram events, with extensive checklists of procedure, personnel, hardware, and activities status at the time of the event.
Particularly notable emphasis was on probing for root, causes, again with suggested questions to be considered during the evaluation.
c.
Isolation valves inside the drywell for. all systems penetrating the containment, and several containment atmosphere control system isolation valves outside the containment were found in their proper closed positions.
d.
The chemistry laboratory scheduled sampling program for November 1, 1985 through January 1,
1985 appeared to include the specific sampling activities and frequencies identified in the technical specifications, within the work scope of the chemistry laborator I*
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Specific procedures appeared to'e available for each of several tests questioned by the inspector.
In addition to the technical specification freqencies, the inspector noted that reactor coolant chloride and conductivity are evaluated daily with regard to acceptance criteria, and monitored by management on a daily basis via the morning planning meetings.
No violations or deviations were identified.
5.
Surveillance Pro ram Im lementation The inspector ascertained that surveillance of safety-related systems or components was being conducted in accordance with license requirements.
In addition to witnessing and verifying daily control panel instrument, checks, the inspector observed portions of several detailed surveillance tests by operators, shift engineers, and instrument and co'ntrol technicians, including the following:
a.
Procedure 9.3.2 - Traversing in-core probe (TIP) calibration.
b.
Procedure 7.4.4.2.1.1 - Safety Relief Valve accoustic monitor channel checks.
c.
Procedure 7.4.0.5.8 - XPCI safety injection valve (RHR-V-41A)
operability verification.
d.
Procedure 7.4.3.1.1 - APRM/Core thermal power calibration check e.
Procedure 7.4.3.2.1.41 - Condenser low vacuum primary containment isolation channel functional test f.
Procedure 7.4.6.1.2 - Containment isolation valve position verification inside the containment drywell.
During performance of procedure 7.4.6.1.2 the inspector identified three matters which appeared to warrant licensee corrective actions:
(1)
The procedure included checklists (with independent verification required) of individual valves and their elevation and azimuth location.
The location information was insufficient to allow the two equipment operators (and accompanying health physicist) to quickly locate the valves.
As a consequence, on November 14, four personnel spent
minutes or more of unnecessary time in each of several radiation areas, attempting to locate the valves, and in one case unnecessarily entered a high radiation area.
This problem was accented by the fact that the checklist was in some cases incorrect in valve identification number, azimuth or elevation location.'he 3,icensee's ALARA review program did not assure that location'identification information was sufficient to maintain exposures as low as reasonably achievable.
The Health Physics manager committed to an ALARA committee consideration of this matter at the next meeting.
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the operations staff was in the process of revising this procedure to implement changes in the scope and method of manual verification of small diameter vent and drain vlaves.
This matter is an open item.
(85-37-01)
The equipment operators apparently did not notice the abnormal (disconnected and dangling loose) condition of ground wires at two locations where they had focused their attention (conduit at the bulkhead penetration and conduit at an RHR valve), nor did they note the split and separated waterproof jacket on the flexible conduit for valve RHR-41A.
The health physicist did not remove a stray spinwrench on the bonnet of valve HPCS-V-15, but stated that he assumed that someone had deliberately stored it there temporarily (there was no evidence of work in progress in the area).
The inspector advised licensee management that he considered these as additional examples of working level staff insensitivity to apparently minor abnormal conditions of safety related equipment, and additional justification for the November 27, 1985 NRC request for WPPSS attention to this subject.
(85-36-01)
The inspector also noted that normally chain-locked drain valves RFW-V-45A and 45B (3/4-inch valves)
had the chains unlocked and removed and the pipe cap removed.
Work on the associated large bore valve RFW-llB appeare'd partially complete.
Subsequent control room log reviews showed that no deviations had been made in the locked-valve checklist, nor was manipulation of the valves authorized under a Shift Manager approved clearance order.
The Shift Manager concluded that the operators had apparently unlocked and opened the valves in conjunction with work on RFW-V-llB, without implementing the applicable administrative control.
Although NRC regulations do not specifically require the small diameter drain valves to be locked, at the time of the occurrence chains and locks constituted the licensee's administrative control for assuring that, these valves were properly closed.
There was minor safety significance to the event, since excessive leakage through such valves would be identified through (alarmed) unidentified leakage monitoring systems.
At WNP-2, each equipment operator normally carries keys to the various small bore and large bore valve locks, to assure pzompt access under emergency conditions.
However, this results in establi.shed administrative controls (logs) being dependent upon the equi'pment oper'ators'amiliarity with and conscientiousness in implementing such controls.
Failure to effect a locked valve checklist deviation for the above valves was a violation of the specific, administrative procedure and tended to undermine the, basis for confidence in the established controls.
This was identified to the licensee as a violation of Technical Specifications requirements.
(85-37-02)
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6.
Monthl Maintenance Observation Portions of selected'afety-related systems maintenance activi,ties were observed.
By direct observation and review of records the inspector determined whether these activities were consistent with LCOs; that the proper administrative controls and tag-out procedures were followed; and that equipment was properly tested before return to service.
The inspector also reviewed the 'outstanding job orders to determine if the licensee was giving priority to safety related maintenance and to verify that backlogs which might affect system performance were not developing.
'1 a.
The inspector=>accompanied the Assj.stant Operations Manager during one tour'f, radiation areas in 'the turbine generator building.
The manager makes at least" weekly tours of these areas to monitor status of water or steam leaks.
The manager took several actions to tighten, manual valve handles where backseating or tightening decreased leakage.
The inspector noted that observations from these tours were routinely pres'ented at the morning meetings for consideration in maintenance planning.
b.
, Preparations for replacement of a defective traversing in-core probe index machine included preplanning, pretesting, and mockup preparations with the crew planned to work in the radiation zones during this maintenance task.
c.
Craft activities to replace springs on containment atmosphere control valves (a repair arising from WPPSS staff review of operating reactor event reports)
included availability and use of the certified vendor manual and post maintenance testing by operations staff (MWR-AU-2514).
d.
Installation of stiffening plates, on the actuator supports for the B-loop reactor recirculation system discharge valve, included welding by qualified welders and quality control inspection under a
work package compiled.to meet ASME Section XI requirements.
e.
Review of outstanding maintenance work requests (MWRs) included the period of October 1 through November 11.
No violations or deviations were identified.
7.
Startu of Second Recirculation Pum Due to vibration problems associated with Reactor Recirculation Pump 1B, the licensee has not operated the plant with this pump in service during 1985, except for some flow tests and a short period of time with the pump at 15 Hz low speed operation.
The plant has therefore operated at 72'j or lower power level during this period.
During maintenance and unplanned outages in 1985 the licensee installed dampers and stiffeners on valves in the "B" loop, repaired the "B" pump bearing, and installed additional vibration monitoring devices on the pump and at various locations on the
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Using combined stress analysis techniques and vibration monitoring data obtained prior to November 1985, in consultation with the pump manufacturer and the NSSS support staff, the licensee's engineering organization ascertained that:
a.
Operational history of the pump has not introduced unacceptable stresses in the primary system piping or otherwise degraded the piping integrity.
b.
Operational history of the pump has not introduced unacceptable stresses in the pump shaft.
c.
Small bore piping which had previously failed due to fatique factors has been repaired and nondestructively examined to assure that latent defects have been corrected.
Stress analyses show that additional failures are not expected with the reduced vibration levels anticipated during future startup of the "B" pump.
Pump casing vibration has been reduced by about a factor of four.
d.
Valve operator resonance frequencies have been improved so as to be far from the driving frequency of the pump.
e.
Original factory test data for the pump indicate that vibration levels will decrease as pump flow is raised toward full flow design condition.
The licensee prepared a special test procedure for monitoring the startup of the "B" pump and progression to full flow conditions, to be conducted using normal plant operating procedures.
The acceptance and shutdown criteria were examined by the resident inspector and NRC licensing technical staff, along with summary'description of the stress verification actions taken to date.
Data showing comparative vibration performance of "B" loop componants prior to and after pump repairs and valve stiffening/dampening work were. also included in this review.
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The controlled and monitored pump startup planned by the licensee appeared to be conservative and base'd upon appropriate confirmati'on of the acceptable condition of the system.
No violations or deviations were identified.
8.
Plant Events a.
On November 13 (6:06 a.m.)
a reactor scram occurred due to
'ailure of an inverter (IN-3) 'supplying Division I instrument power.
The inspector arrived at, the control room about 6:30 a.m and interviewed control room staff personnel, examined records relating to the evaluation of the event, and attended the morning planning meeting where the occurrence was discussed with plant management.
Subsequent licensee evaluations identified that the Elgar manufactured devices included large 125 VAC capacitors (Cornell-Dubillier) which contained PCB materials.
Failure of the capacitor leaked PCB material into inverter cabinets, which created a maintenance inconvenience.
The plant engineering staff ordered
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replacement capacitors for all inverter equipment for future installation to eliminate similar future difficulties of personnel protection and PCB disposal.
This demonstrated foresightedness and attention to detail by the plant support. staff.
In addition, the inspector walked through the procedure 3.3.1 in detail, to consider items which were not applicable during the particular scram event which occurred (i.e. automatic containment isolations).
Several discrepancies were identified in the checklist provided for manual verification of containment isolation valve functioning in response to isolation signals.
(The checklist was not required to be used for this particular event, since the procedure specified it to be applicable only when the Graphics Display System is inoperable).
The following discrepancies were conveyed to the Operations Manager for consideration:
(1)
The checklist called for all but one discharge valve (SGT-V-5A-1) on standby gas treatment systems to be closed, thus resulting in only one operating train, whereas two operating trains are required.
(2)
The checklist appeared to omit automatic isolation valves CSP-V-93 and 98 and TIP isolation valves from required verification.
(3)
Some valves which have been deactivated and locked closed were included in the list, such that there was no longer control room indication of their position; the operator would have to leave the control panel area to perform verifications (e.g.
steam condensing mode valves RHR-V-llA and B, and RCIC-V-64).
(4)
Some valves were misidentified (e.g.
SGT-V-52A in lieu of MOA-V-52A, FDR-V-154 in lieu of FPC-U-154).
(5)
Section 3.3.1.5.B identified the sequence of operation of safety relief valves to equalize heat load to areas of the suppression pool during reactor pressure control, and sequence 11 and 12 both specified valve MS-RV-2C (sequence 11 apparently should be valve MS-V-1B).
However, recent human factors changes to the control panels have included the appropriate numbers, corrected as described in paragraph 10.a.l, below.
b.
On November 17 (3:46 a.m.)
a reactor scram occurred due to high neutron flux protective actions activating before the operator could increment the Intermediate Range Monitors (IRMs).
The inspector was notified by the licensee at 4:40 a.m.
and arrived on-site 8:30 a.m.
to interview the operations staff, review the computer post-trip data and scram report, and observe activities to restart the plant.
A thorough analysis of the event/time data was performed by the plant nuclear engineer, who was assisted by corporate core performance engineering personnel who had been called to the site to assist in verification of control rod worth calculations.
The plant nuclear engineer had been on duty at the time of the control rod
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movements during the initial startup, and stayed for assistance during the recovery startup.
At the time of the scram the plant was in the startup phase, with control rods being withdrawn.
Intermediate range monitors (IRMs)
were at about 67/ of range four, reactor period was about 60 seconds and increasing, and the operator had just withdrawn the next control rod the 2-notches prescribed by the approved rod sequence checklist.
Within 10 seconds after the control rod had settled into position, the first IRM high level (108%) alarm activated; 4-6 seconds later redundant IRM channels reached the 120/ trip point and the scram occurred, before the operator could select and increment the IRM range switches upward (a 32 second reactor period was present during this time).
The operator had not expected the neutron flux level to increase as rapidly as it did.
The nuclear engineer concluded that the particlar control rod was in the central region of the core and had particularly high control worth due to the current 5400 MWD/ton exposure of the reactor core.
However, the operators'rior startup experience apparently biased their thinking to expect slower neutron response than actually occurred.
With plant management approval, the nuclear engineer adjusted the rod withdrawal sequence for the recovery startup and discussed the current core physics behavior with the operators.
The scram report and data showed that the plant responded as designed, including the IRM alarm and scram functions.
The cause of the scram was determined, corrective actions taken, and plant management approval obtained prior to recovery.
No violations or deviations were identified.
9.
Iicensee Event Re orts A regional inspector performed an in-office review of the following Xicensee Event Report (LER) relative to timeliness, adequacy of description, generic implications, planned corrective actions, and adequacy of coding.
The resident inspector reviewed the following report and supporting information on site to verify that licensee management had reviewed the event, corrective action had been taken, no unreviewed safety questions were involved, and violations of regulations or Technical Specification conditions, if any, had been identified.
LER-85-023-02 (Open)
Electrical Separation - The WPPSS revised report was submitted September 9,
1985 and committed to training of craft personnel on proper use of temporary cables.
This training was conducted about November 9, and appeared to cover all the craft personnel.
The training session monitored by the inspector provided abbreviated guidance on options for routing temporary cables.
The sessions were conducted by a responsible enginee '
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The LER also committed to a quality assurance evaluation, which was conducted as described.
A design evaluation has been in progress, and WPPSS has contracted with Wylie Laboratories for fire propagation tests which are expected to verify that cable tray covers are not required in some raceway configurations.
WPPSS has deferred installation of omitted cable tray covers pending receipt and evaluation of test results.
No violations or deviations were identified.
10.
Licensee Actions On Previous NRC Ins ection Findin s The inspector reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
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Unresolved Item (85-30-04 and 85-21-03, Closed) - Perceived inadequacy of the Electrical Separation Practices document introduced questions relating to previously accepted resolutions of cable separation issues.
A detailed review by the licensee and by the inspector ascertained that questionable areas were limited to the currently identified prime circuit discrepancies, as discussed in paragraph ll.c, below.
This item is closed.
ll. S ecial Ins ection To ics a.
Detailed Control Room Desi n Review During routine control room observations the inspector verified the implementation of s'elected actions described in the November 1,
1985 licensee summary report to NRC.
Specifically:
(1)
Task TA-5.1.2, Steam valve MS-V-69 and safety relief valve (SRV) control labels had been revised or added as described.
Tag MD-V-69 was revised as described in the summary report.
However, the inspector found that SRV manual operating-sequence numbers 11 and 12, described in emergency procedure 5.1.2, had erroneously been interchanged when translated to the identification tags on the control panel.
The control room operators promptly contacted the system engineer to resolve the discrepancy.
(2)
Task 13.3.19 (NRC F-4.36).
For the scram discharge volume bypass keylock switch, the licensee's latest response noted that the switch will not be replaced, and did not address intentions regarding the prior commitment to retain the key in
'he switch., Plant startup procedures did not include instructions regarding this key, and operating crew practices did not appear consistent in this matter (although the inspector routinely observed the key in place during 1984-1985, on November 18, 1985 he noted that the key was not in the switch with the plant at, 40% power).
However, this key was encompassed'y the gene'ral key control procedure and its
, location routinely audited by the shift managers.
The Operations Manager clarified in the night order log, his
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expectation that the key be maintained in the keylock switch during normal operations.
(3)
Task 10.3.1 (NRC E-5.62).
Significant color banding had been added to control room instruments, particularly ECCS, ESF and electric power meters.
(4)
Task 24.4.5 (NRC E-5.11).
An ADS bypass switch had been
'added, along with an associated Bypass/Inoperative Status
','ndicator light.
- .r (5)
Task 14.5.5;2.b (NRC E-3';71).
- Mushroom button heads had been installed for acknowlege-controls, and accent color padding was in. place.
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Task (NRC D-6.91).
Spray pond level color banding had been added to level'ndicators.
(7)
Task 24.5;,5 (NRC-C9.2).
RHR steam condensing mode had been deactivated';
some controls and instruments were still in place, eventually to be removed from-the panels.
(8)
Task 14.5.2.1 (NRC C3.13)'.
An aggressive licensee program had reduced the number of nuisance alarms significantly.
(9)
Task N-4.
Temporary cardboard glare shields had been in place at the'turbine DEH control panel since occurrence of a plant trip event in 1984.
b.
Power Reactor Events at Other Sites The October 1985 issue of NRC Report of Power Reactor Events, item 2.11, identified a potential problem with bypassing of standby gas treatment filters via common unvalved drain lines.
The inspector reviewed the WNP-2 design drawings and thereby ascertained that check valves are included in such drain lines at WNP-2.
c.
Electrical Racewa Se aration Discre ancies Found In 1984 As a result of cable tray separation discrepancies identified by the licensee in event report 85-023, the inspector conducted a detailed review of the licensee's findings and corrective actions.
This also included a re-review of the disposition of prior electrical separation and identification issues (1978 through 1983 period),
including thirteen prior NRC inspection findings (78-09-05, 79-04-07/08, 80-07-01, 81-17-05,'2-21-01 through 06, and 83-38-14)
and eight licensee construction deficiency reports (licensee reports Nos.
29, 37, 49, 50, 54, 82, 102, 223 and 246).
The re-review emphasized evaluation of the impact of the current findings on the validity of prior conclusions regarding adequate resolution of the prior issues, and particularly those matters whose resolution referenced utilization of the Electrical Separation Practices (ESP)
criteria document issued March 1983.
The inspector evaluated the clarity of the electrical separation inspection criteria used during
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prior licensee reviews and hardware inspections, in light of the hardware discrepancies identified under LER-85-023.
Except for the current subject of prime circuits, the inspector found no basis to challenge the resolution of the prior electrical separations issues.
The licensee's quality assurance organization conducted a detailed review of prior engineering and inspection efforts to determine how 10,000 feet of omitted tray covers could have been missed by prior special hardware verification activities and corrective action programs.
The review also included an assessment of the most recent WPPSS engineering corrective actions, including training of the twelve engineers who performed the walkdown inspections of cable trays designated as "Prime".
The inspector examined the quality assurance summary reports and the supporting reference documents.
The supporting records of the quality assurance review demonstrated that thorough hardware inspections had been conducted by Bechtel during 1983, and that the 1985 WPPSS engineering hardware inspections were likewise thorough and conducted with clear acceptance criteria.
These efforts all focused on verification of conduit-to-tray and tray-to-tray separation in accordance with the approved ESP (Revisions 2 through 4).
Conduit and tray labelling were also included in the earlier Bechtel efforts.
The plant records showed that the criteria used by Bechtel inspectors during their'983 efforts did not clearly include criteria relating to prime circuits.
Such criteria were not in the ESP Revision 2 Appendix A (Field Verification) section intended for use by field inspection personnel (Especially Table A-9).
This was clearly the root cause for the omissions, and has been recognized and addressed, by',the licensee's engineering and quality assurance reviews.
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matter appears to have been adequately reported to NRC under
CFR 50.72, with corrective actions 'partially completed to date.
The WPPSS engineering staff was anticipating that engineering tests underway under contractto WPPSS willverify'that the current prime cable -installations are, acceptable as installed.
After due consideration'of severity 'level, corrective action and reporting provisions per
CFR 2 Appendix C, the inspector identified no violations or deviation /
During the review of this matter the inspector noted nonconformance report284-0272, dated'April 2,.1984 'his NCR consituted a
,compilation of findings regarding discrepancies in cable terminations, which were identified while Bechtel quality control inspectors were performing cable separation inspections during February - April 3983.
The plant technical staff dispositioned the NCR as "Use-As-Is" on November ll, 1985, with a followup implementation action to reinspect all panels and components and identify any rework which may be required.
The responsible supervisor stated that the interim Use-As-Is disposition was based upon the presumption that verification activities and associated corrective actions subsequent to the individual (}CIR findings (such
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as startup tests and technical specification surveillance testing)
have proven the systems', ability to perform their functions as-is.
He stated that the current status of individual findings had not yet been positively ascertained, and would,be scheduled for inspection in December.
The inspector noted that the failure to address the Bechtel (}CIRs was similar to the observations by the NRC Construction Assessment Team in June 1983 (Ref.
NRC Inspection Report 83-29, Paragraph ll and Report 83-38 Paragraph 5.1), where the Supply System had not docum'ented resolution of incidental QCIRs generated by Fishbach/lord electrical contractor inspectors.
During the week of November 25, the licensee's corporate quality assurance auditors conducted the routine 6-month audit of corrective actions programs, as required by the Technical Specifications.
During this audit, the auditors found a few additional unresolved NCRs which appeared to also have warranted earlier corrective action.
The inspector interviewed one auditor and examined prior audit findings in the area of corrective actions for the 1984-85 period.
I The audit findings indicated that the backlogs of nonconformance reports had been increasing and that plant management had increased emphasis on reducing the backlog in recent months, apparently in response to 1985 corporate office compiled trending data.
The recent disposition of the NCR in question apparently was a
constructive result of this effort, and the audit findings focused corrective action on the re-evaluation of long outstanding NCRs.
The WPPSS progress on this mattex will be a followup item for future NRC.inspections.
(85-37-03)
Cold Weather Protection Measures NRC Bulletin 79-24 requested licensees of operating plants to consider adequate measures to protect safety related equipment from freezing; WNP-2 was not yet licensed to operate at, that time.
Subsequently, WPPSS personnel reviewed the Bulletin and concluded that no action was planned since WNP-2 safety related piping was determined to be adequately protected from freezing (Ref.
NRC Inspection Report 80-06).
No particular documented program was developed by WPPSS to assure adequate preparations for winter conditions.
Since plant startup in January 1984, preparations for cold weather conditions were apparently not conducted on a programmed basis.
Steps were, however, taken by plant staff to correct frozen piping and cooling towers, and alarmed failures in trace heating circuits, on an ad hoc and troubleshooting basis.
Inspection report 84-31 identified a trace heating, problem which was not initially adequately addressed.
In October 1985, the licensee accidentally identified a frozen line in the fire protection system, which had occurred due to unknown valve leakage into the normally isolated and dry piping.
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During the current'inspection report period,'he inspector interviewed the WPPSS fire protection engineer, who attested to having personally verified the operability of room heaters at the fire pumps.
Interviews with other plant staff indicated that consideration was being given to address other cold weather concerns.
In early November the inspector initiated a review of outstanding maintenance work requests and incomplete design changes associated with trace heating or other cold weather protection, and found that there had apparently not been any licensee coordinated effort to assure that these had been reevaluated for priority in view of the recent onset of cold weather.
Plant management advised that a cold weather preparations procedure had been prepared to provide more orderly assurance that various necessary aspects of this matter would be considered.
The procedure had not yet been issued on November 20, when temperatures were already below freezing.
(There was no specific technical specification surveillance requirement for this matter, which would mandate this formalization and scheduling of cold weather evaluations.)
The licensee's actions in this area did not appear to have been timely, although attention appears to be improving.
The inspector did not identify any safety related equipement which became inoperable as a result of inattention to this area.
This area will be the subject of future inspection activities.
(85-37-04)
12.
Licensee Action on
CFR 50.55(e)
Construction Deficienc Re orts Various construction deficiency reports were issued by the licensee during the construction phase of the project.
Those reports of conditions and corrective actions taken or planned were reviewed by NRC regional staff at. the time of submission.
Fulfillment of reporting requirements, report completeness, corrective actions, generic aspects of the items, and need for on site followup were evaluated.
With the exception of the following two items, NRC inspection reports have documented the NRC followup reviews or site inspection activites for all prior construction deficiency reports.
Licensee actions relative to the following reports were reviewed on site in conjunction with review of licensee event report LER-85-023 and appeared acceptable:
a.
Item 79-07-A Iicensee Re ort Numbers
49
and 54-Electrical Se aration and Im ro er Installation (Closed)
These reports documented licensee actions to correct electrical separation problems.
Final corrective actions were accomplished in conjunction with corrective actions for subsequent enforcement items.
The November 1985 licensee quality assurance reviews considered the prior corrective actions relative to the findings of LER-85-023 and affirmed satisfactory prior resolution of the issues, as discussed in paragraph 10.c, abov /
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b.
Item 80-09-A Licensee Re ort Number 82 Lack of Installation Documentation For Class lE Cables In Main Control Room Closed)
This report documented the corrective actions taken relative to the quality assurance program breakdown associated with the Power Generation Control Complex (PGCC) electrical cable installation.
Licensee followup actions were examined by NRC inspectors as documented princially in inspection reports 78-09, 79-07, 80-06, 81-09, 82-28, and 83-18; the described corrective actions appeared acceptable.
Correction of hardware aspects of PGCC cable separation was also addressed in the MPPSS final report number 64.
The inspector examined Bechtel correspondence used as a basis for the conclusions of the final report and a sample of referenced engineering directives records and quality control inspection records (QCIR's)
which demonstrated that correction of the control room cable separation problems had been completed.
No violations or deviations were identified.
13.
Mana ement Meetin The Senior Resident'nspector met with the project manager approximately weekly during this period, to discuss inspection finding status.
Prior to the exit meeting, the inspector met with the plant Compliance Engineer, to review principal inspection findings and discuss commitments and planned actions by licensee staff.
On November 27, 1985 the inspector met with the t'lant Manager and members of his staff to discuss the inspection findings during this period and obtain management positions and confirmation, of commitment ~ m P
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